Graduation project mostafa 2017 by Gama Eldien

Acknowledgment

DEDICATION

To all those who have helped us in our live by encouraging and support, to our family , our teachers ,and our friends. Thanks to you all

Chapters Chapter 1

Geology

1.1 Location 1.1.1 The western desert geology 1.1.2.Company foundation 1.1.2.1 Agiba operating areas 1.1.2.2 Meliha concession 1.1.2.3 Gawher field 1.2.1 Petrolum system analysis in Meliha concession. 1.2.1.1 Regional geological framework 1.2.1.1.1 Stratigraphy and Sedimentology 1.2.1.1.1.1 source rock

1.2.1.1.1.2 Reservoir rock Bahyria formation Reservoir zonation and depositional environment The importance of faulting to the prospectively of the concession: Trapping mechanism 1.2.2 Gological Map 1.2.2.1 contour lines 1.2.2.2 Types of geological Maps 1.2.2.3 Types of subsurface Maps 1.2.2.3.1 structure contour Map 1.2.2.3.2Cross sections 1.2.2.3.3 panel/Fence diagram 1.2.2.3.4 isofacies Map 1.2.2.3.5 paleogeologic and subcrop Maps 1.2.2.3.6 Miscellaneous Maps 1.2.2.3.7 Hydronamic Maps 1.2.2.3.8 Geophysical Maps 1.2.2.3.9 Geochemical Maps 1.2.2.3.10 Iso-hydrocarbon Maps 1.2.2.3.11 Isopach and isochore Maps

Chapters 1.2.2.4 Methods of drawing 1.2.2.5 Bahyria Maps 1.2.2.5.1 Strucure contour Maps BAH-1&BAH-3 1.2.2.5.2 BAH-1 Isopach Map 1.2.2.5.3 BAH-1 Iso-hydrocarbon Map 1.2.2.5.4 BAH-1 Iso-porosity Maps 1.2.2.5.5 BAH-1 Iso-saturation Maps 1.2.2.5.6 BAH-1 Gross sand Map 1.2.2.5.7 correlation stratigraphic cross section and 2-d panel diagram of western deSert: 1.2.2.5.8 Lithofacies Maps of the western desert 1.3.3 Volume of oil in place calculations 1.3.3.1 Bulk volume calculations 1.3.3.1.1 calculation methods 1.3.3.1.1.1 Trapezoidal Method 1.3.3.1.1.2 pyramid Method 1.3.3.1.1.3 simpson Method 1.3.3.1.2 calculation procedure and Results 1.3.3.1.2.1 Using structure contour Map 1.3.3.1.2.2. Averaging Reservoir Rock Properities 1.3.3.1.2.3 Using Isopach Map 1.3.3.1.2.4 Using Iso-hydrocarbon Map 1.3.3.4 probabilistic Estimation of OOIP using Monte carlo: 1.3.3.4.1 Technique procedures 1.3.3.4.2 For BAH-1 1.3.3.4.3 Data Entry and results.

Chapters Chapter 2

Drilling Engineering

2.1 Introduction 2.2 Methods of drilling wells 2.3 Drilling Team 2.4 Rotary Drilling Equipment 2.5 THE DRILLING PROCESS 2.6 Selection of the drilling rig type 2.6.1 Onshore (Land) Rigs 2.6.2 Offshore (Marine) Rigs 2.6.2.1 Barge (Submersible) Rigs 2.6.2.2 Jack-up Rigs 2.6.2.3 Fixed Platforms 2.6.2.3.1 Piled Steel platforms 2.6.2.3.2 Gravity Structures 2.6.2.4 Semi-Submersible Rigs 2.6.2.5 Drill Ships 2.7 Pressure definitions 2.7.1 Hydrostatic Pressure 2.7.2 Formation or pore pressure 2.7.3 Over burden pressure 2.7.4 Fracture pressure 2.8 Determination of number of casing strings 2.9 Casing terminology and Design 2.9.1 Functions of Casing 2.9.2 Types of Casing 2.9.2.1 Stove Pipe 2.9.2.2 Conductor Pipe 2.9.2.3 Surface Casing 2.9.2.4 Intermediate Casing 2.9.2.5 Production Casing and Liners 2.10 Casing design 2.10.1 Sources of data 2.10.2 Factors affecting casing design 2.10.2.1 Collapse Criterion 2.10.2.2 Burst criterion 2.10.2.3 Tensile criterion 2.10.3 Casing design methods 2.10.3.1 Casing design methods

Chapters 2.11 Cementing 2.11.1 Functions of Cement 2.11.2 Cement and cementing additives 2.11.3 Slurry testing 2.11.4 Classification Criteria 2.11.4.1 API Classification System 2.11.4.2 Classes and types of cement 2.11.5 Cement placement techniques 2.11.5.1 Primary cement job 2.11.5.2 Secondary or squeeze cement job 2.11.6 Methods of Cementing 2.11.6.1 Single Stage Cementing 2.11.6.2 Multi stage Cementing 2.11.6.3 Liner Cementing 2.11.7 Casing and cementing accessories 2.11.8 Cementing design 2.11.8.1 Two types of cement calculations 2.12 Drill String Design 2.12.1 Introduction 2.12.2 Components of the drill string 2.12.3 Drill pipes 2.12.3.1 Drill Pipe Grade 2.12.3.2 Drill Pipe Classification 2.12.4 Drill Collars types 2.12.5 The criteria of drill string design 2.12.5.1 Collapse design 2.12.5.2 Tension Design 2.12.6 Drill Collar Design 2.13 Directional Drilling 2.13.1 Directional Drilling Technique 2.13.2 The applications of directional drilling 2.13.3 Considerations of Directional Well Path 2.13.3.1 Target location 2.13.3.2 Target size and Shape 2.13.3.3 Rig location 2.13.3.4 Subsurface obstacles 2.13.3.5 Geological Sections 2.13.3.6 Casing and Mud program 2.13.4 Basic hole patterns 2.13.5 Deflection tool 2.13.5.1 Whip Stocks

Chapters 2.13.5.2 Jetting 2.13.5.3 Down hole motor and bent sub 2.13.5.4 Steerable Drilling Systems 2.13.6 Types of directional surveys 2.13.7 Directional Drilling Design 2.14 Drilling Rig 2.14.1 Elements of drilling rig 2.14.2 Components of drilling rigs 2.14.2.1 Hoisting System 2.14.2.2 Rotary system 2.14.2.3 Slush (or Mud) pumps 2.14.2.4 Prime movers and transmissions 2.14.2.5 Drilling fluid circulating system 2.14.2.6 Well control system 2.14.2.7 Well monitoring system 2.14.3 Calculation for Well Gawaher N- 4 2.14.4 Ton Miles of Drilling Line 2.14.5 Derrick efficiency factor DEF 2.15 Mud Circulation System 2.15.1 Surface Connection Losses (P1) 2.15.2 Pressure Drop across Bit 2.15.3 Pipe and Annular Pressure Losses 2.15.4 Calculation of pressure losses 2.15.5 Mud pump Horse power calculations 2.16 Pressure Control (BOP Selection) 2.17 Calculating average Penetration Rate 2.18 The Trip time per trip vs. depth 2.19 Total Drilling Cost 2.20 Drilling problems 2.21 References

Chapter 3

Reservoir Engineering

3.1. INTRODUCTION 3.1.1. VOLUMETRIC ANALYSIS 3.1.2. MATERIAL BALANCE ANALYSIS APPLICATIONS OF MBE GENERAL DIFFICULTIES IN MBE LIMITATIONS OF MBE 3.2. SOURCES OF RESERVOIR ENERGY 3.2.1. WATER DRIVE 3.2.2. SOLUTION GAS DRIVE 13

Chapters 3.2.3. ROCK AND LIQUID EXPANSION 3.2.4. GAS CAP DRIVE 3.2.5. GRAVITY DRAINAGE 3.3. GAWAHER FIELD RESERVOIR SUMMARY 3.3.1. RESERVOIR FLUID PROPERITIES 3.3.2. RESERVOIR CHARACTERISTIC 3.4. DATA ACQUIZATION AND PROCESSING 3.4.1. PVT data adjustment 3.4.1.1. Flash Vaporization Test 3.4.1.1.1. Test data 3.4.1.1.2. RESULTS 3.4.1.2. Differential Vaporization Test 3.4.1.2.1. results 3.4.1.3. Separator Test 3.4.1.4. PVT Data Adjustment 3.4.1.4.1. Oil Formation Volume Factor Adjustment 3.4.1.4.2. Solution Gas-Oil Ratio Adjustment 3.4.1.4.3. Adjusted PVT Data 3.4.2. Averaging Reservoir Rock Properties 3.4.2.1. Averaging Reservoir Porosity 3.4.2.2. Averaging Connate Water Saturation 3.4.2.3. Averaging Net/Gross Ratio 3.4.2.4. Reservoir Average Petrophysical Properties 3.4.2.4.1. Bahariya I 3.4.2.4.1. Bahariya III 3.4.2.5. Normalization and Averaging of relative permeability data 3.4.2.5.1. Normalization and averaging Procedure 3.4.2.5.2. Normalization of relative permeability 3.4.2.5.3.Averaging of normalized data and denormalization 3.4.2.6. averaging capillary pressure curves 3.4.2.6.1. Given 3.4.2.6.2. Fitting an average curve for J_function 3.4.2.6.3. RESULTS

Chapters Chapter 4

Logging

4.1. INTRODUCTION 4.1.1. TYPES OF WELL LOGGING 4.1.2. Objectives of well logging 4.1.3. Logging evolution 4.1.4. Logging Steps 4.1.5. LOGGING TOOLS 4.1.5.1. GAMMA RAY LOG 4.1.5.2. POROSITY LOGS 4.1.5.3. LATERO LOGS 4.2. QUANTITATIVE INTERPRETATION 4.2.1. Procedure 4.2.2. Calculations 4.2.2.1. Calculate the shale content 4.2.2.2. Corrections 4.2.2.3. Correction for hydrocarbon effect 4.2.2.4. Determination of water resistivity Rw 4.2.2.5. Calculation of oil saturationt 4.3. QUALITATIVE INTERPRETATION 4.3.1. well logs 4.3.2. QUALITATIVE INTERPRETATION 4.3.3. Net Pay and Reservoir Pay, depending on cutoffs 4.4. Quantitative interpretation 4.4.1. Shale volume calculations 4.4.2. Porosity reading corrections 4.4.3. Effective porosity and saturation 4.4.4. RESULTS 4.4.5.Crossplots for zones BAH-I, BAH-II, BAH-III 4.4.5.1. ARG 4.4.5.2. BH1 4.4.5.3. BH3 4.4.5.4. BH5 4.4.6. PICKETT CROSS PLOT

Chapter 5

WELL TEST

5.1 Introduction 5.2 Objectives of well Test Operations 5.3 Drill Stem Test(DST). 5.3.1. Drill stem test function 5.3.2 Types of Drill Stem Tests 15

Chapters 5.3.2.1 Open Hole Drill Stem Testing 5.3.2.2 Cased Hole Drill Stem Testing 5.3.3. Conducting Drill Stem Test 5.3.4. Test Choke 5.3.5 Potential Hazards 5.3.6. Possible Solutions. 5.4 Types of Tests 5.4.1 Drawdown Test 5.4.2 Buildup Test 5.4.3 Injection Test 5.4.4 Fall off Test 5.4.5 Interference Test 5.5. Some important concepts in well test 5.5.1 The Skin Effect 5.5.2 effective wellbore radius 5.5.3 Flow Efficiency 5.5.4 Wellbore Storage 5.6 Reservoir Boundary Response 5.6.1Closed Boundaries 5.6.2 Fault Boundaries 5.6.3 Constant Pressure Boundaries 5.7 Estimation of average reservoir pressure 5.7.1 Middle Time Region Method 5.7.2 Late-Time Region Methods 5.8 Type Curve Analysis 5.9 Some types for buildup curves 5.10 Analytical Method 5.11 Saphir method 5.12 Comparison between analytical Method and saphir Modeling 5.13 References

Chapter 6 6.1 6.2

Production Engineering

General Introduction Inflow Performance Relationship 6.2.1 Under saturated Reservoirs 6.2.2 Saturated Reservoirs 6.2.3 Generalized Vogel inflow performance 6.2.4 Current and predicted IPR 6.2.4.1 Vogel Method 6.2.4.2 Beggs Method 6.2.4.3 Fetkovich Method 16

Chapters 6.3 Vertical lift performance 6.4 WELL COMPLETION 6.4.1 Introduction 6.4.2 Completion of naturally flowing wells 6.4.2.1 Reservoir completion methods 6.4.2.2 Upper completion methods 6.4.3 Open-hole 6.4.4 Cased hole completion ` 6.4.5 Main configurations of production strings 6.4.6 The equipment of naturally flowing wells 6.5 ARTIFICIAL LIFT METHODS 6.5.1 Introduction 6.5.2 Methods of Artificial Lift Systems 6.5.2.1 Gas lift 6.5.2.2 Pumping System 6.5.2.2.1 Sucker Rod Pump 6.5.2.2.2 Hydraulic Jet Pump 6.5.2.2.3 Hydraulic Piston Pump 6.5.2.2.4 Electric Submersible Pump (ESP) 6.5.2.2.5 Progressive Cavity Pump 6.5.3 Artificial Lift Selection 6.5.4 Our Project Artificial Lift Methods 6.5.4.1 ESP Design 6.5.4.1.1 Using EXCEL 6.5.4.1.2 Using PROSPER 6.5.4.2 SUCKER ROD PUMP DESIGN 6.6 Field Processing 6.6.1 OIL AND GAS SEPARATION 6.6.1.1 Separator Components 6.6.1.2 Types of Mist Extractors 6.6.1.3 Types of separator 6.6.1.4 DESIGN OF STAGE SEPARATION 6.6.1.5 Separator Calculations 6.6.1.6 Graphical Method 6.6.1.7 Heater Treater 6.6.1.8 Design of Heater Treater 6.7 References

FoRward

Petroleum is an industry that supports the activities of a range of other industries. It is a science which demand an over view of all other engineering branches such as mechanical , electrical , chemical,…etc. and related branches of science such as mathematics, physics, geology,…etc. The primary objective of our project is to enhance our engineering sense and to enable us to be good players in teamwork. Our study in the faculty depends on teaching us the basics and concepts of petroleum engineering, so the role of our project is to develop our engineering sense to use these concepts in industrial applications A Petroleum engineer plays in a large team which consists of mechanical engineers, electrical engineers, geologists…etc. so in our project we are supposed to identify the ability of working as a group: 1- Meeting periodically. 2- Co-operation in teaching each other`s functional objectives. 3- Building trusts and mutual respect. 4- Each member in the team learns to be a good teacher. 5- Each member subordinates their ambitions and egos to the goals of the team.

Project Team Work

Chapter 1

Geology

Chapter 1

Geology

GENERAL OVERVIEW

1.1 Location 1.1.1 The western desert geology The western desert covers 700,000 Sq. KM, about two third of Egypt it extends 1000 KM from the Mediterranean Sea to the Sudanese border in the south and 60 to 800 KM from Nile valley to the Libyan border in the west.

1.1.2 Company foundation Agiba Petroleum Company (Agiba) was founded in 1981 as an operating company.

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Geology

Figure 1 - Geological Map of Egypt

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Geology

1.1.2.1 Agiba Operating Areas

Figure 2-Agiba operating Areas

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Geology

1.1.2.2 Meleiha Concession: The Meleiha Development Lease, located in the Western Desert of Egypt, 65 km South of the Marsa Matruh town, covers an area of approximately 700 sq km.

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Geology

Regional Tectonic Setting:

In Meleiha area the extension through faulting took place during two main per Late Jurassic-Early Cretaceous and Turonian-Early Tertiary. The second Phase cause reactivation of the first phase with a generation of just new minor faulting. In between these two periods of faulting, subsidence occurred through flex down warping of the North Western desert. Faulting style is predominantly extensional, although strike slip movement must have occurred because of the variation in trend of faults. The degree of movement may not be significant regionally; however wrench or oblique slip movements may have contributed to the formation of structures proximal to the concerned and may have generated local compression.Fault movement contribute subsidence and locally represents the main control during tectonic periods. Sediments ranging in age from Palaeozoic to middle Miocene have been encountered during drilling in the area.

Migration

For the potential traps at Bahariya level, migration requires faulting. Since the area quite heavily faulted, migration of hydrocarbon to these younger level can be expected due to faulting.

Seal

The structure exist in Bahariya formation is three way dip closure The Intraformational shale and limestone of Abu Roush â&#x20AC;&#x153;Gâ&#x20AC;? Member and Upper Bahariya shale and carbonate facies are acting as a vertical seal for Lower Bahariya.

Chapter 1

Geology

1.1.2.3 GAWAHER Field: • Gawaher field is located in Meleiha concession in western desert , was discovered by drilling exploratory well ( N . Gawaher -1X). • Geological model indicated that this field is faulted anticline structure produces from different layers mainly shaly sand and sand with different thickness .The main producing formation is baharyia which will present the main target formation. • Production started from Bahariya formation in JAN. 2007 from well (N. Gawaher -3) with initial rate 64 BOPD and 1% W.C , field development continued up to date with drilling wells( N. Gawaher -4) ,( N. Gawaher -5) ,( N. Gawaher -6) ,( N- Gawaher -7) ,( N- Gawaher -8) . • Initial reservoir pressure at datum of 5848 ft/S.S was 2350 Psia and initial reservoir temperature at 174 F . •Current oil rate is182 BOPD and 41 % W.C and current reservoir pressure in (PSIA @datum)

1.2.1 Petroleum System Analysis in Meleiha Concession: I n Egypt, the Mesozoic petroleum system is known to be active in the Western Desert region. The Meleiha area is one of the highest potential areas in the Western •Surrounded by very rich hydrocarbon generating basins (Shushan & Matruh basins). •Occupied with two troughs: 1. The central trough, represented by a graben structure bounded by Meleiha West-Meleiha SE fields and the Bardy structure. 2. The Northern trough, represented by a monocline structure located North of the Aman-Meleiha NE fields. 25

Chapter 1

Geology

Any petroleum system consists of:

1.2.1.1. Regional Geological Framework

• Stratigraphy and Sedimentology [to understand source & reservoir rock] • Structural Tectonic analysis [to understand Migration & Trapping] 1.2.1.1.1. Stratigraphy and Sedimentology: 1.2.1.1.1.1 Introduction • The area consists of four main depositional cycles. • Each cycle began during a regressive phase of deposition and ended during a phase of maximum transgression. • Separated by main regional unconformities. Other local unconformity exists as the result of the regional Syrian Arc tectonic event. • The sedimentary cover within the northern coastal basins reaches 14,000 ft • Meleiha -1x well was chosen as a representative well for field stratigraphy in Meleiha field (EGPC/SSI 1990.)

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Geology

Figure 2 Stratigraphic Column of Western Desert

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Geology

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Geology

Figure 3 litho-stratigraphic column of Meleiha concession

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Geology

Figure 4 -Typical log for western desert stratigraphic column

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Geology

1.2.1.1.1.1. Source Rock • Khatatba Formation coaly section. • Plant derived kerogens. • Deposition environment in freshwater lakes on the coastal/flood plain. • Khatatba Formation thickness [20’ south: 120’ north] is likely to be poor and insufficient to generate hydrocarbons. This area may have to rely on long distance migration from ‘kitchen’ elsewhere

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Geology

1.2.1.1.1.2. Reservoir Rock â&#x20AC;˘Main prospective geological formations

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Geology

Bahariya Formation Age:

Upper Cretaceous- Lower Cenomanian.

Thickness: • Bahariya Formation occurs all across the Concession area and is penetrated by virtu ally all wells, being the principal target and producing Formation. • ‘niform in thickness ranging from 947’ (E. Salam-1X) to 681’ (N. Nada 2X). However, a complete sequence is only seen in few wells. The isopach map appears slightly thickening to the north-eastern part. The formation is predominantly a sequence of interbedded argillaceous Sandstones and shale with subordinate carbonates layers which act as local markers.

Chapter 1

Geology

Reservoir zonation

â&#x20AC;˘Dividing Bahariya Formation into six zones based on facies variation and logging â&#x20AC;˘Reflects gross vertical changes in lithology and their horizontal, lateral continuity â&#x20AC;˘The main problems associated with constructing a zonation of Bahariya a)Local lithological variations due to rapid lateral facies changes. b)Incomplete sequences where wells reach TD within the Bahariya FM. c)Faulting, leading to the removal of parts of zones in some wells.

Depositional environment: The degree of marine influence is highly variable. The lower part of the Bahariya Formation is characterized by a predominantly siliciclastic succession, deposited in an overall tidal dominated environment (Fig.3.3.8.2). The upper part of Bahariya is characterized by a rapid alternation of carbonate, mixed and siliciclastic levels, resulting in a complex facies assemblage that may have deposited in carbonate lagoons, along an embayed coastline, with sporadic terrigenous runoff from land. In between the two sequences a widespread carbonate dominated level is present. This overall Bahariya depositional environment is quite homogeneous all over the area, thus lateral variations of the lithologic facies could happen very quickly and in a short distance, due to the high lateral variability of the tidal and nearshore environment sedimentary features.

Chapter 1

Geology

The Lower Cenomanian Bahariya Formation corresponds to a second-order depositional sequence that formed within a continental shelf setting under relatively low-rate conditions of positive accommodation (<200 m during 3â&#x20AC;&#x201C;6 My). This overall trend of base-level rise was interrupted by three episodes of base-level fall that resulted in the formation of third-order sequence boundaries. These boundaries are represented by sub aerial unconformities (replaced or not by younger transgressive wave ravinement surfaces), and subdivide the Bahariya Formation into four third-order depositional sequences. The construction of the sequence stratigraphic framework of the Bahariya Formation is based on the lateral and vertical changes between shelf, subtidal, coastal and fluvial facies, as well as on the nature of contacts that separate them. The internal (third-order) sequence boundaries are associated with incised valleys, which explain (1) significant lateral changes in the thickness of incised valley fill deposits, (2) the absence of third-order highstand and even transgressive systems tracts in particular areas, and (3) the abrupt facies shifts that may occur laterally over relatively short distances. Within each sequence, the concepts of lowstand, transgressive and highstand systems tracts are used to explain the observed lateral and vertical facies variability. This case study demonstrates the usefulness of sequence stratigraphic analysis in understanding the architecture and stacking patterns of the preserved rock record, and helps to identify 13 stages in the history of base-level changes that marked the evolution of the Bahariya Oasis region during the Early Cenomanian. 1. The unconformity-bounded Bahariya Formation is a second-order depositional sequence, as representing a major subdivision of the first-order Jurassicâ&#x20AC;&#x201C;Cenomanian passive margin succession of the Western Desert in Egypt. 2. The construction of the third-order sequence stratigraphic framework for the Bahariya Formation was based on a detailed sedimentological study, and paleo-depositional environment interpretations, performed in five main localities in the Bahariya Oasis. 3. Eight distinct facies associations have been recognized, corresponding to changes in clastic lithology, color, sedimentary structures and stratal stacking patterns. These facies associations reflect shifts in paleo-depositional environments from outer shelf (deepest marine facies recorded in the study area) to shoreface, coastal, and fluvial (high and low energy systems). 4. Lateral and vertical changes of facies, as well as the nature of facies contacts, are explained by using a sequence stratigraphic model in which systems tracts and sequence stratigraphic surfaces are linked to particular stages in the evolution of the basin. These stages reflect consistent trends of aggradation, progradation, retrogradation or erosion at the thirdorder level of stratigraphic cyclicity. 35

Chapter 1

Geology

5. The Bahariya Formation is composed of four stacked depositional sequences, each corresponding to a stage of overall base-level rise in the basin. Sequence boundaries signify stages of base-level fall, whose magnitudemay be estimated fromthe amount of valley incision as inferred from the thickness variation of lowstand deposits across the Bahariya Oasis. 6. The history of base-level changes and associated shifts in depositional trends has been reconstructed for thirteen consecutive time steps during the Early Cenomanian interval, showing repeated cycles of lowstand normal regressions, transgressions and highstand normal regressions, separated by stages of fluvial valley incision. 7. At least two generations of incised valley systems have been identified, which explain the absence of some systems tracts in particular areas, significant thickness variations of incised valley fills, and the abrupt lateral facies changes observed across relatively short distances.

1.2.1.1.1.2.1.1 The importance of faulting to the prospectively of the concession: Faults and folds in Shushan Basin are very important controls on reservoir morphology and fluid movement. Identification of the fault types which occur in a particular reservoir is a vital step in defining reservoir geometry Sediment accumulation: On subsidence [grabens] Hydrocarbon migration Movement on faults will have juxtaposed permeable layers at different levels potentially enabling the passage of hydrocarbons up section across faults from Khatatba source rocks to Bahariya levels. Trapping mechanism a) Structural Traps I.Majority fault-assisted traps [1-way ,2-way,3-way dip] E.g. At the Bahariya level a three-way dip closure bounded to the North by a NW-SE trending normal fault down throwing to the North.

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Geology

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Geology

II. Minority, Anticlines [four-way dip-closure] E.g. the Alam El Bueib unit III D , At Masajid level

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Geology

b) Stratigraphic Traps: • Exist due to the lateral facies variations in each of the three major potential reservoir. • Risky due to limited thickness of the intraformational vertical seals and the presence of a fault network. • Less risky if supported by structural component.

Sealing

The risky factor for these structures: • The presence of adequate top and lateral sealing. • The integrity of the trap for each prospect has to be assessed according to the juxtaposed formations and the thickness of the potential reservoirs across the fault throw together with the thickness of the potential lateral and vertical seals.

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Geology

Stratigraphic traps:

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Geology

Examples for Dry wells due to lack of seal around the fault

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Geology

1.2.2. Geologic Maps

Geologic maps are used to • Show the geologic history of the region. • Predict the location of petroleum pools of the new geologic data uncovered. • Determine the location of source rock and the reservoir rock. • Determine the kind of trap. • Estimate the initial hydrocarbon in place.

1.2.2.1. Contour lines: A contour line is a line that passes through points having the same elevation A contour line is a line that passes through points having the same elevation 1.2.2.1.1. Characteristics of contour lines: • Contour lines are continuous. • Contour lines are relatively parallel unless one of two conditions exists. • A series of V-shape indicates a valley and the V’s point to higher elevation. • A series U shape indicates a ridge. The U shapes will point to lower elevation. • Evenly spaced lines indicate an area of uniform slope.

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Geology

1.2.2.2. Types of geologic maps

1.2.2.3. Types of subsurface maps:

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Geology

1.2.2.3.1. Structure contour maps = Structural maps: Like topographic [surface] maps but with differences

1.2.2.3.2 Cross Sections (CS): To clearly display some details about structures, Types

1.2.2.3.3Panel / Fence diagram: Isometric projection of structural/stratigraphic section. Facies maps are of several kinds, but those most used in the geology of petroleum are lithofacies maps. They can be divided into: â&#x20AC;˘ Lithofacies maps Distinguish the various lithological types rather than formations â&#x20AC;˘ Isolith maps Shows the net thickness of certain lithology specially sandstone.

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Geology

1.2.2.3.5 Paleogeologic and Subcrop Maps: • Paleogeology the science that treats the geology as it was during various geologic periods • A paleogeologic map Shows the paleogeology of an ancient surface. • A subcrop map A paleogeologic map in which the overlying formation is still present where as a paleogeologic map shows the formation boundaries projected in part into the area from which the overlying formation has been eroded. 1.2.2.3.6 Internal property maps= Miscellaneous Maps: Maps detect the characteristics of a single unit and its shape.

Types

Chapter 1

Geology

1.2.2.3.7 Hydrodynamic maps: • These maps represent the relation between equipotential surface of oil and water in the reservoir. • They represent the surface normal to which the movement of two fluids takes place. • It gives information about the direction of fluid movement, density of water and density of oil. 1.2.2.3.8 Geophysical maps: • These maps depend on geophysical anomaly (such as Bouger anomaly maps magnetic anomaly maps –resistivity anomaly maps etc.) 1.2.2.3.9 Geochemical maps: • These maps are used for mapping various kinds of chemical analysis of rocks and their fluid contents. • It may show the surface distribution of hydrocarbons where those hydrocarbons are found at the surface in large amounts than normal indicating that there is a seepage of oil or gas. 1.2.2.3.10 Isohydrocarbon maps : Hydrocarbon potential = net pay thickness * porosity * hydrocarbon saturation

1.2.2.3.11 Isopach vs Isochore

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Geology

The thickness displayed by isochore is equal or greater than that of isopach when the top and bottom surface of layer are:

Horizontal

[TST(isopach)=TVT(isochore)]

Inclined

[TST(isopach)<TVT(isochore)] 1.2.2.3.11.1Pay zone 1.2.2.3.11.1.1Definition Reservoir intervals that will contribute to reservoir production. 1.2.2.3.11.1.2 Importance: guide to perforation depths and in the computation of field reserves.Intervals that are accepted or eliminated from consideration as pay are done so on the basis of their fluid saturation content, porosity, permeability, and shaliness. according to cut-offs applied to logs and curves calculated from logs. 1.2.2.3.11.1.3 Types: a) Gross reservoir interval: the unit between the top and base of the reservoir that includes both reservoir and non-reservoir intervals; b) Gross sandstone (or limestone, dolomite, carbonate): the summed thickness of intervals that are determined to be sandstone, usually determined by a Vsh. cut-off. c) Net sandstone (or limestone, dolomite, carbonate): the summed thickness of gross sandstone zones that have effective porosity and permeability, usually determined by a porosity cut-off; d) Gross pay thickness: the summed thickness of net sandstone zones that has hydrocarbon saturation considered sufficient for economic production, usually determined by a water-saturation cut-off e) Net pay thickness: the summed thickness of gross pay zones that should yield water-free production, usually determined by an irreducible bulk volume water cut-off 1.2.2.4 Methods of Drawing Two ways of drawing the maps have been followed;

Chapter 1

Geology

1.2.2.4.1 Structural contour map construction procedures:

1.2.2.5 Bahariya Maps: Using location map, for determining wells and fault locations, and formation properties measured at each well; We managed to generate different maps for Bahariya formations using Surfer software. These maps are shown as follows ,

Chapter 1

Geology FOR BAH 1

1.2.2.5.1 Structural Contour Map for BAH-1:

Chapter 1

Geology For BAH3

Chapter 1

Geology

1.2.2.5.2 Isopach Map:

Chapter 1

Geology

1.2.2.5.3 Iso-hydrocarbon Map

1.2.2.5.4.Iso-porosity Maps:

Chapter 1

Geology

1.2.2.5.4.Iso-porosity Maps:

Chapter 1

Geology

Chapter 1

Geology

1.2.2.5.6 Gross sand map:

Chapter 1

Geology

1.2.2.5.7 correlation stratigraphic cross section and 2-d panel diagram of western desert:

Chapter 1

Geology

1.2.2.5.8 Lithofacies Maps of the western desert:

Figure 7 lithofacies maps of the western desert.

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Geology

1.3.3 Volume of oil In-Place Calculations: There are several methods for calculating the Initial Hydrocarbon In-Place (IHIP), - Original Oil In-Place (OOIP), Original Gas In-Place (OGIP) or both- such as • Volumetric Analysis • Material Balance Analysis • Decline Curve Analysis • Analogy Both Material Balance Analysis (MBA) and Decline Curve Analysis (DCA) are discussed in details in Reservoir Engineering Section. But what matters here in Petroleum Geology section is the Volumetric Analysis for calculating the OOIP, which is considered the most valuable method for estimating the OOIP in the early life of the field. Volumetric Analysis is also known as the “geologist’s method” as it is based on cores, analysis of wireline logs, and geological maps. Knowledge of the depositional environment, the structural complexities, the trapping mechanism, and any fluid interaction is required to: • Estimate the volume of subsurface rock that contains hydrocarbons. The volume is calculated from the thickness of the rock containing oil or gas and the areal extent of the accumulation • Determine a weighted average effective porosity • Determine a weighted average water saturation. With these reservoir rock properties and utilizing the hydrocarbon fluid properties original oil-in-place or original gas-in-place volumes can be calculated. • Porosity • Net thickness • Hydrocarbon saturation • Areal extent of the reservoir For oil reservoirs, the mathematical expression for original oil in place (OOIP) by volumetric method can be written as follows:

Chapter 1

Geology

1.3.3.1 Bulk Volume Calculation 1.3.3.1.1 Calculation Methods The bulk volume of the reservoir V¬B can be calculated using different methods but the most common ones are •Trapezoidal Method • Pyramidal Method • Simpson’s method

1.3.3.1.1.1 Trapezoidal Method:

Bulk volume can be calculated as follows

Equation 1 - Trapezoidal rule for calculating bulk volume This method requires that area ratio AnAn−1>0.5

1.3.3.1.1.2 Pyramidal Rule:

Bulk volume can be calculated as follows

Equation 2 - Pyramidal rule for calculating bulk volume This method requires that area ratio A_n⁄A_(n-1) ≤ 0.5 1.3.3.1.1.3 Simpson Method Bulk volume can be calculated as follows

Equation 3 – Simpson rule for calculating bulk volume This method requires odd number of contour lines 1.3.3.1.2 Calculation Procedure and Results • Using formation top and bottom structural contour map • Using Isopach Map Note: The bulk volume to be calculated is the bulk volume of trapped oil zone bounded by the fault as the sealing element. 59

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Geology

1.3.3.1.2.1Using Structural Contour Map:

Figure 10 Blanked Map

Figure 11 - Calculating the volume between formation top and bottom using Surfer(R) 60

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Geology

Figure 12 Sample of volume report generated by Surfer

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Geology

1.3.3.1.2.2 Averaging Reservoir Rock Properties: Arithmetic averaging usually does not properly represent the average value of the reservoir property, so weighted averaging of the property can be the solution for better representation of reservoir property. 1.3.3.1.2.2.1AveragingReservoirPorosity: Weighted averaging of reservoir porosity can be calculated using the following equation. Equation 4 - Reservoir Porosity Weighted Averaging 1.3.3.1.2.2.2Averaging Connate Water Saturation: Weighted averaging of reservoir connate water saturation can be calculated using the following equation.

Equation 5 - Connate Water Saturation Weighted Averaging 1.3.3.1.2.2.3 Averaging Net/Gross Ratio Weighted averaging of reservoir net/gross ratio can be calculated using the following equation. Equation 6 - Net/Gross Weighted Averaging 1.3.3.1.2.2.4 Reservoir AveragePetrophysical Properties:

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Geology

1.3.3.1.2.3 Calculating OOIP From Equation -1

So for BAH-I

1.3.3.1.2.4 Using Isopach Map:

Chapter 1

Geology

Chapter 1

Geology

1.3.3.1.2.5 Using iso-hydrocaron map: Those maps are used directly to calculate the initial oil in place ,As it represents the hydrocarbon distribution through the reservoir. It can determine the potential economic areas. From surfer program

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Geology

Figure 13 calcaluated volume from iso-hydrocarbon map

Chapter 1

Geology Calculating OOIP

1.3.3.4 Probabilistic Estimation of OOIP using Monte Carlo: Estimation of volume in place is carried out under conditions of uncertainty. The method of estimation is called deterministic if a single best estimate of reserves is made based on known geological, engineering, and economic data. The method of estimation is called probabilistic when the known geological, engineering, and economic data are used to generate a range of estimates and their associated probabilities. In the previous calculations we used deterministic method for calculating the OOIP. However, this can be less accurate because we are not taking the probabilities of required properties into consideration. • It’s a computerized Technique to determine the impact of Certainty and Uncertainty. • Petroleum Engineers use this technique to determine the STOIIP and GIIP accounting the different available values for the input parameters. • Deterministic Methods for calculating the Reserves becomes no longer in use nowadays, and Probabilistic Method should now come on Screen. Now we are going to apply Monte Carlo technique as a probabilistic method for estimating the OOIP, in which Each of the parameters involved in the calculation of reserves; the PVT properties and pore volume are represented by statistical distributions. These statistical distributions can be in the different forms including

Chapter 1

Geology

Chapter 1

Geology

1.3.3.4.1Technique Procedure:

1.3.3.4.2For BAH-I: 1.3.3.4.2.1 Porosity Distributions

â&#x20AC;˘ From the figure, Distribution of BAH-I Porosity matches log-normal Model. â&#x20AC;˘Required Parameters

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Geology

1.3.3.4.2.2Oil Saturation Distributions:

â&#x20AC;˘Required Parameters

1.3.3.4.2.3 Net to Gross distribution: â&#x20AC;˘ From the figure, Distribution of BAH-I Porosity matches log-normal Model.

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Geology

â&#x20AC;˘ Required Parameters

1.3.3.4.3Data Entry and Results: After identifying property distribution type and calculating required parameters, we are going to use Monte Carlo Technique in MBalÂŽ to generate probabilistic distribution of OOIP in BAH-I reservoir.

Figure 21 Data Input

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Geology

Figure 22 BAH-1 Property Distribution Entry in Mbal.

Figure 23 Monte Carlo Analysis for BAH-1 72

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Geology

Figure 24 Summary of Results

â&#x20AC;¢Results

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Geology

References: 1.Shalaby, Shouhdi E. Petroleum Geology Maps and Cross Sections. s.l. : Suez university, faculty of petroleum & mining engineering. 2.Schlumberger. Geology of Egypt. 3.Leverson, frdreick and Berry, a. F. Geology of petroleum. Barkly, California :University of California,Barkly, W. H. Freeman and Company. 5. Younes, M. A. Hydrocarbon Potentials in the Northern Western Desert of Egypt . 2014. 6. Agiba Petroleum Company. Agiba Annual Report. 2012. 7. Daniel J.TearPock,Richard E.Bischke:â&#x20AC;? Applied Subsurface Geological Mappingâ&#x20AC;? (1990).

Chapter 2

Drilling

Chapter 2

Drilling

Agenda 1-Introduction to Drilling Engineering. 2-Design Considerations • Casing Strings Required and Their Setting Depths. • Production Casing String Design Program. • Cementing Program for The Production Casing String •Drill String Design. • Selection of The Drilling Rig Required and Its Components Design • Mud Program. • Drilling Progress Statistics. • Average Penetration Rate in Each Formation Unit drilled • Determination of Rotating Time vs. Depth • The Trip Time per Trip vs. Depth • Total Trip Time vs. Depth • Total Drilling Costs for the Well. 3-Drilling problems during drilling the well and their remedy

General InFormation About The Well

•Operator: •Well: •Area: •Agiba Supervisors: •Drilling contractor: •RIG: •Authorized Total depth: •M-I engineers:

Agiba Pet. Co. Gawaher. No.4 Gawaher/Western Desert

MohammeTaha/Khaled Elkayal Saipem Saipem G-125 6500 ft. M.Mokhtar

Chapter 2

Drilling

2.1 Introduction: OILWELL drilling is one of the most important branches of petroleum industry .Drilling is widely used in exploration for oil &natural gas in the early stage of a search for oil. When a seismograph surveying is used to discover geological structures favorable of oil and gas accumulation, it is necessary to drill shallow wells to make explosions. There are many indirect methods (geophysical and geochemical aspects) for prospecting for oil and natural gas, but such methods indicate that certain possibilities exist for oil and gas accumulation. These methods canâ&#x20AC;&#x2122;t prove presence of oil in a favorable areas. They give no opportunity for estimation for a deposit (oil and gas traps) which is supposed to be discovered. Drilling well is the only method to find oil and gas and prove the profitability of oil and gas traps discovered. After discovering oil and gas traps, it is necessary them from the deep underground to make them available for further processing and consumption. As oil is usually accumulated in deep strata, the most economical method of extracting it is to drill wellbores which can serve as conduits for oil or gas from their traps to surface. Wells are drilled for not only extracting oil or gas but also for the purposes of injecting water, gas, steam into oil bearing strata to maintain formation pressure, to apply secondary recovery methods, etc.

2.2 Methods of drilling wells: Many methods are used in drilling wells involving rock disintegration, but only mechanical drilling is widely used for drilling oil and gas wells

Chapter 2

Drilling

2.3 Drilling Team: Many specialized talent are required to drill a well safely and commercially. As in most complex industries, many different services companies, contractors, and consultant, each with its own organization, have evolved to provide necessary services and skills. Specialized groups identifiable as within the major oil companies also have evolved. A staff of drilling engineers is generally one of these groups.

Chapter 2

Drilling

2.4 ROTARY DRILLING EQUIPMENT: The first planned oil well was drilled in 1859 by Colonel Drake at Titusville, Pennsylvania USA. This well was less than 100 ft deep and produced about 50 bbls/day.

A conventional cable tool rig The cable-tool drilling method was used to drill this first well. The term cable tool drilling is used to describe the technique in which a chisel is suspended from the end of a wire cable and is made to impact repeatedly on the bottom of the hole, chipping away at the formation. When the rock at the bottom of the hole has been disintegrated, water is poured down the hole and a long cylindrical bucket (bailer) is run down the hole to collect the chips of rock. Cable-tool drilling was used up until the 1930s to reach depths of 7500 ft. In the 1890s the first rotary drilling rigs were introduced. Rotary drilling rigs will be described in detail later but essentially rotary drilling is the technique whereby the rock cutting tool is suspended on the end of hollow pipe, so that fluid can be continuously circulated across the face of the drillbit cleaning the drilling material from the face of the bit and carrying it to surface. This is a much more efficient process than the cable-tool technique. The cutting tool used in this type of drilling is not a chisel but a relatively complex tool ( drillbit ) which drills through the rock under the combined effect of axial load and rotation and will be described in detail later. The first major success for rotary drilling was at Spindletop, Texas in 1901 where oil was discovered at 1020 ft and produced about 100,000 bbl/day.

Chapter 2

Drilling

A conventional rotary drilling

2.5 THE DRILLING PROCESS: The operations involved in drilling a well can be best illustrated by considering the sequence of events involved in drilling the well shown. The dimensions (depths and diameters) used in this example are typical of those found here in Egypt but could be different in other parts of the world. For simplicity the process of drilling a land well will be considered below.

â&#x20AC;˘ A sketch of well

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Drilling

2.6 Selection of the drilling rig type:

2.6.1 Onshore (Land) Rigs: Before rig equipment is brought in, the land must be cleared and graded, and access roads must be prepared. The most common arrangement for a land drilling rig is the cantilever mast (sometimes called a jack-knife derrick) which is assembled on the ground, then raised to the vertical position using a power from the draw works (hoisting system). These structures are made up of prefabricated sections which are fastened together by large pins. First, the drilling crew places the engine and derrick substructures in proper position and Pinned together, and then the draw works and engines are put in place. The derrick sections are then laid out horizontally, pinned together, and the mast is raised as a unit by the hoisting line, traveling block and draw works.

Chapter 2

Drilling

2.6.2 Offshore (Marine) Rigs:-

2.6.2.1 Barge (Submersible) Rigs: The barge is a shallow draft, flat-bottom vessel equipped as an offshore drilling unit, used primarily in swampy areas. This rig can be found operating in the swamps of river deltas in Waste Africa or in the coastal areas of shallow lakes such as Lake Marcaibo, Venezuela. It can be towed to the location and then blasted to rest on the bottom.

2.6.2.2 Jack-up Rigs: This mobile drilling rig is designed to operate in shallow water, generally less than 350 ft deep. Jack-up rigs, are very stable drilling platforms because they rest on the seabed and are not subjected to the heaving hull which may be ship-shaped, triangular, rectangular, or irregularly shaped, supported on a number of lattice or tubular legs. When the rig is undertow to a drilling location the legs are raised, projecting only a few feet below the deck, and the structure behaves like a cumbersome floating box; hence, it can be towed only in good seas and at a slow speed. Upon reaching its location the legs are lowered by electric or hydraulic jacks until they rest on the seabed and the deck is level, some 50 feet or more above the waves. Most jack-up rigs have three; four or five legs are either vertical or slightly tilted for better stability. In one design, they are fixed to a large steel mat, which gives it the name of mat-supported jack-up. A drilling derrick is cantilevered over the side. The chief disadvantages of the jack-up are its vulnerability when being jacked up or relocated, but as a class, they are cheaper than other mobile rigs. Nearly half of the worldâ&#x20AC;&#x2122;s fleet of offshore rigs in service is the jack-up type, some of which are large, self-propelled Units.

Chapter 2

Drilling

2.6.2.3 Fixed Platforms: 2.6.2.3.1 Piled Steel platforms : These are conventional drilling and production platforms, and hundreds of them are installed offshore in many parts of the worlds. The standard configuration consists of a steal jacket pinned to the seabed by long steel piles, surmounted by a steel jack 128 deck with supports equipment and accommodation buildings or modules, one or more drilling rigs, and a helicopter deck. Piled steel platforms have the advantage of being very stable under the worst sea conditions, but they are virtually immobile. In shallow waters the plied platforms is probably preferred over the jacket in separate sections usually begins onshore. They are then assembled on a flotation tanks, then up righted, and finally submerged over the chosen spot on the seabed. The jacket is then pin-piled, the â&#x20AC;&#x153;superstructureâ&#x20AC;? and accommodation modules or buildings erected, and the platform made ready for operations.

Piled Steel platforms 2.6.2.3.2 Gravity Structures: This is a family of deep-water structures usually built of reinforced concrete, but may be of steel or a combination of steel and concrete. These structures rely on gravity to keep them stable of the seabed. Unlike piled steel platforms, they are relatively mobile and need no piling to hold them in place. Gravity structures tolerate a wide range of seabed conditions. While they can be used for development drilling and production, they also have the advantage of being able to store oil in their structural cells structure, each of which is constructed to client requirements.

Chapter 2

Drilling

Gravity Structure platform

2.6.2.4 Semi-Submersible Rigs: These are floating drilling rigs consisting of hulls or caissons, which carry a number of vertical stabilizing columns, support a deck with derrick, and associated drilling equipment. Semi-submersible drilling rigs differ principally in their displacement, hull configuration, and the number of stabilizing columns. Most modem type have a rectangular deck, a few are cruciform shaped, others pentagon shaped, while some of the smaller rigs have a triangular deck. The semi-submersible is very stable because its center of gravity is low in water. It can operate in deeper water than a jack-up rig. Operational depth is limited principally by the mooring equipment and by riser. However, some units have a capability of drilling in 500 meters of water with the aid of â&#x20AC;&#x153;dynamic positioningâ&#x20AC;?. 84

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Drilling

2.6.2.5 Drill Ships: These are ships or â&#x20AC;&#x153;floatersâ&#x20AC;? specially constructed or converted for deep-water drilling. Drill ships offer greater mobility than either jack-up or semi-submersible rigs, but are not as stable when drilling, their main advantages is an ability to drill in almost any depth of water. Many are anchor-moored, but modem ships are fitted with dynamic positioning equipment, which enables them to keep on-station above the borehole. Having greater storage capacity than other types of rigs of comparable displacement, drill ships are often is to drill deeper wells, operate independent of service, and supply ships. A feature of drill ships with automated station-keeping facilities is their ability to maneuver accurately with the aid of thrusters fitted with controllable pitch propellers.

Chapter 2

Drilling

Types of offshore rigs

Chapter 2

Drilling

2.7 Pressure definitions

2.7.1 Hydrostatic Pressure: Hydrostatic pressure is the pressure exerted by a column of fluid. This pressure is a function the average density of fluid and its vertical depth. Mathematically Hydrostatic pressure is expressed as:

where

2.7.2 Formation or pore pressure: Is the pressure acting on the fluids in the pore space of rocks, Divided in three categories: 1) Normal pore pressure:- formation pressure is equal to the hydrostatic pressure of formation pressure extending from surface to subsurface formation. 2) Abnormal pore pressure:- any pore pressure that is greater than the hydrostatic pressure of formation fluid occupying pore space (Sometimes called (Over pressure - Geopressure) **this pressure is the cause for using BOP

3) Subnormal pressure :- any pore pressure less than hydrostatic pressure

2.7.3 Over burden pressure : Is the pressure exerted by the weight of overlying formation above point of interest. Total weight = rock weight + fluid weight Mathematical expression

Chapter 2

Drilling

More useful equation

2.7.4 Fracture pressure : Is the minimum pressure required to overcome the wellbore stresses in order to fracture the formation. Fracture pressure is equal to minimum horizontal stress. Evaluation of fracture gradient: 2 methods

1) HUBBERT AND WILLIS METHOD: The Hubbert and Willis method is based on the premise that fracturing occurs when the applied fluid pressure exceeds the sum of the minimum effective stress and formation pressure. The fracture plane is assumed to be always perpendicular to the minimum principal stress. According to the Hubbert and Willis method, the total injection (or fracturing) pressure required to keep open and extend a fracture is given by:

where Ď&#x192; â&#x20AC;˛ 3 is the effective minimum principal stress (= minimum principal stress minus pore pressure)

Chapter 2

Drilling

2) EATON METHOD: It is widely used in the oil industry, stating the rock deformation is elastic

where :

Here the equations and steps for determining the required number of casing strings and their setting depth using EATONâ&#x20AC;&#x2122;s method

2.8 Determination of number of casing strings:

Chapter 2

Drilling

Chapter 2

Drilling

2.9 Casing terminology and Design:

2.9.1 FUNCTIONS OF CASING: 1. To keep the hole open and to provide support for weak, vulnerable or fractured formations. In the latter case, if the hole is left uncased, the formation may cave in and redrilling of the hole will then become necessary. 2. To isolate porous media with different fluid/pressure regimes from contaminating the pay zone. This is basically achieved through the combined presence of cement and casing. Therefore, production from a specific zone can be achieved. 3. To prevent contamination of near-surface fresh water zones. 4. To provide a passage for hydrocarbon fluids; most production operations are carried out through special tubings which are run inside the casing. 5. To provide a suitable connection for the wellhead equipment and later the christmas tree. The casing also serves to connect the blowout prevention equipment (BOPS) which is used to control the well while drilling. 6. To provide a hole of known diameter and depth to facilitate the running of testing and completion equipment.

2.9.2 TYPES OF CASING: In practice, it would be much cheaper to drill a hole to total depth (TD), probably with a small diameter drill bit, and then case the hole from surface to TD. However, the presence of high-pressured zones at different depths along the wellbore, and the presence of weak, unconsolidated formations or sloughing, shaly zones, necessitates running casing to seal off these troublesome zones and to allow the drilling to TD. Thus, different sizes of casing are employed and this arrangement gives a tapered shape to the finished well. 2.9.2.1 Stove Pipe: Stove pipe (or marine-conductor, or foundation-pile for offshore drilling) is run to prevent washouts of near-surface unconsolidated formations, to provide a circulation system for the drilling mud and to ensure the stability of the ground surface upon which the rig is sited. This pipe does not usually carry any weight from the wellhead equipment and can be driven into the ground or seabed with a pile driver. A typical size for a stove pipe ranges from 26 in. to 42 in. 91

Chapter 2

Drilling

2.9.2.2 Conductor Pipe: Conductor pipe is run from the surface to a shallow depth to protect near surface unconsolidated formations, seal off shallow-water zones, provide protection against shallow gas flows, provide a conduit for the drilling mud and to protect the foundation of the platform in offshore operations. One or more BOPs may be mounted on this casing or a diverter system if the setting depth of the conductor pipe is shallow. In the Middle East, a typical size for a conductor pipe is either 18 5/8 in. (473 mm) or 20 in. (508 mm). In North Sea exploration wells. the size of the conductor pipe is usually 26 or 30 in. Conductor pipe is always cemented to surface. It is used to support subsequent casing strings and wellhead equipment or alternatively the pipe is cut off at the surface after setting the surface casing. Conductor pipes are either driven by a hammer or run in a drilled hole or run by acombination of drilling and driving especially in offshore operations where hard boulders are encountered. 2.9.2.3 Surface Casing: Surface casing is run to prevent caving of weak formations that are encountered at shallow depths. This casing should be set in competent rocks such as hard limestone. This will ensure that formations at the casing shoe will not fracture at the high hydrostatic pressures which may be encountered later. The surface casing also serves to provide protection against shallow blowouts, hence BOPs are connected to the top of this string. The setting depth of this casing string is chosen so that troublesome formations, thief zones, water sands, shallow hydrocarbon zones and build-up sections of deviated wells may be protected. A typical size of this casing is l3 3/8 in. (240 mm) in the Middle East and 18 5/8 in. or 20 in. in North Sea operations. 2.9.2.4 Intermediate Casing: Intermediate casing is usually set in the transition zone below or above an over-pressured zone, to seal off a severe-loss zone or to protect against problem formations such as mobile salt zones or caving shales. Good cementation of this casing must be ensured to prevent communication behind the casing between the lower hydrocarbon zones and upper water formations. Multistage cementing may be used to cement this string of casing in order to prevent weak formations from being subjected to high hydrostatic pressure from a continuous, long column of cement. The most common size of this casing is 9 5/8 or 10 Âž in. 2.9.2.5 Production Casing: Production casing is the last casing string. It is run to isolate producing zones, to provide reservoir fluid control and to permit selective production in multizone production. This is the string through which the well will be completed. The usual sizes of this string are 4 1/2, 5 and 7 in. 92

Chapter 2

Drilling 2.9.2.5.1 Liners:

A liner is a string of casing that does not reach the surface. Liners are hung on the intermediate casing by use of a liner-hanger. In liner completions both the liner and the intermediate casing act as the production string. Because a liner is set at the bottom and hung from the intermediate casing, the major design criterion for a liner is usually the ability to withstand the maximum expected collapse pressure.

TYPES OF LINERS 1. Drilling liners are used to isolate lost circulation or abnormally pressured zones to permit deeper drilling. 2. Production liners are run instead of a full casing to provide isolation across the production or injection zones. 3. The tie-back liner is a section of casing extending upwards from the top of an existing liner to the surface. It may or may not, be cemented in place. 4. The scab liner is a section of casing that does not reach the surface. It is used to repair existing damaged casing. It is normally sealed with packers at top and bottom and, in some cases, is also cemented. 5. The scab tie-back liner is a section of casing extending from the top of an existing liner but does reach the surface. The scab tie-back liner is normally cemented in place. ADVANTAGES OF A LINER The main advantages of a production liner are: The disadvantages of a liner are: (a) Total costs of the production string are re- (a)possible leak across a liner hanger; duced, and running and cementing times are re- (b)difficulty in obtaining a good primary duced. cementation due to the narrow annulus (b) The length of reduced diameter is reduced between the liner and the hole. which allows completing the well with optimum sizes of production tubing. 93

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Drilling

2.10 Casing design:

2.10.1 Sources of data:

2.10.2 Factors affecting casing design: 2.10.2.1 Collapse Criterion: Collapse pressure originates from the mud used to drill the hole, and acts on the outside of casing. Since hydrostatic pressure increase with depth, so collapse pressure is maximum at the bottom of hole and zero at surface. â&#x20AC;˘Following assumptions are used for collapse design, 1-Casing is assumed empty. 2-Internal pressure inside casing is zero. 3-External pressure is caused by mud in which casing is run in. 4-No cement outside casing.

Chapter 2

Drilling

2.10.2.2 Burst criterion: In oil well casings, burst occurs when the effective internal pressure inside the casing (internal pressure minus external pressure) exceeds the casing burst strength. Like collapse, the burst calculations are straightforward. The difficulty arises when one attempts to determine realistic values for internal and external pressures. In development wells, where pressures are well known the task is straight forward. In exploration wells, there are many problems when one attempts to estimate the actual formation pressure including: • the exact depth of the zone (formation pressure increases with depth) • type of fluid (oil or gas) • porosity, permeability • temperature

2.10.2.3 Tensile criterion: Most axial tension arises from the weight of the casing itself. Other tension loadings can arise due to: bending, drag, shock loading and during pressure testing of casing. In casing design, the uppermost joint of the string is considered the weakest in tension, as it has to carry the total weight of the casing string. Selection is based on a design factor of 1.6 to 1.8 for the top joint. Tensile forces are determined as follows: 1. calculate weight of casing in air (positive value) using true vertical depth; 2. calculate buoyancy force (negative value); 3. calculate bending force in deviated wells (positive value); 4. calculate drag force in deviated wells (this force is only applicable if casing is pulled out of hole); 5. calculate shock loads due to arresting casing in slips; and 6. calculate pressure testing forces.

In the initial selection of casing, check that the casing can carry its own weight in mud

and when the casing is finally chosen, calculate the total tensile loads and compare them with the joint or pipe body yield values, using the lower of the two values. A design factor (= coupling or pipe body yield strength divided by total tensile loads) in tension of 1.6 to 1.8 should be used.

Chapter 2

Drilling

2.10.3 Casing design methods: 2.10.3.1 Production Casing string design methods:

1) For collapse at lower part:

â&#x20AC;˘ STEP 1 :

Minimum collapse resistance for the bottom section is

Where:

P hydrostatic = 0.052 * Îłm * H Where:

Chapter 2

Drilling

â&#x20AC;˘ STEP 2

From Rabia tables, 7 in casing select the grade and typical tensile load and the internal pressure.

â&#x20AC;˘ STEP 3

The length of the bottom section is determined as follows

Where:

Generally:

2) For tensile load at upper part:

Chapter 2

Drilling

3) Checking for burst pressure at the weakest grade:

Method 2-Graphoanalytical

Chapter 2

Drilling

Design of liner casing & surface casing using analytical method: 1) Design for liner casing Given the following data for liner casing:

Ph = 0.052 * ÎłM * h =.052*9.8*6500 =3312.4 psi Pc min = Ph*1.125 =1.125*3312.4 =3726.45 psi

1-Determine the length of grade J55 26 lb. Pc2=3270 psi Pc2=1.125*Ph @ shoe of J55 23 lb 3270=1.125*.052*9.8*(H-L1) L1=796.2 feet No. of joints=L1/40 No= 20 L1=800 feet

where

Chapter 2

Drilling

2-Determine length of J55 23 lb. Pc3= 2270 psi Pc3 = 1.125 * P hydrostatic @ the shoe of J55 “20 lb.” 2270 = 1.125*0.052*9.8* ( H – L1 – L2) L2=1740.5 feet No. of joints =L2/40 No=44 L2=1760 feet

where

3-determine length of grade J55 20 lb L3= Total length - L1 –L2 L3= (6500-2853) - 800- 1760 L3=1087 feet No. of joints= 28 L3=28*40= 1120 feet

2. Check for tensile load for J55 “20 lb”At the upper part of the casing: Tensile load = Σwi *Li =20800+40480+22400 =83680 lb γ min = 316000 psi Fc =316000/83680= 3.77 > 1.8

Safe Design

100

Chapter 2 2.

Drilling

for Burst pressure:

So, the production casing string design is as follows

2) Design of surface casing for well: 1- Design for collapse pressure

101

Chapter 2

Drilling

2- Check tensile stress at the upper part of casing:

102

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Drilling

Casing String Design Using Grapho-analitical method

On graph, Draw this point on collapse resistance axis

Select grade L-80, 26 as grade one, so the lower part of the well consists of grade N-80 with N.W. 26 lb. /ft.

First section grade L-80 with N.W 26 lb/ft Assume that the whole casing string consists of grade L-80 with N.W. 26 lb. /ft

From figure, by drawing a line with those values of Pc min and W1, it is shown that it will intersect with the gradeJ-55#23 lb/ ft

103

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Drilling

From fig, for grade J-55#23 lb. /ft

Second section grade J-55 with N.W 23 lb/ft Assume that the whole casing string above the first section of grade J-55 23 lb/ft

- From figure, By drawing a line with those values of Pc 2 and W2, it is shown that it will intersect with the grade J-55,20 lb. /ft. From fig, for grade J-55#20 lb. /ft

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3rd section grade J-55 with N.W. 20 lb. /ft

Check for tensile load

Check for burst pressure

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Comment The casing used in the well is only one grade and have a grade greater than the required as indicated above, but this may be due to the company make design for all the wells in the field and they select the greater grade for all the wells and use only one grade to buy only type of casing and this is more economical

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liner hanger We choose the thick-walled TruFormÂŽ liner-hanger system from Halliburton has been tested to rigorous ISO 14310 standards and is V0 qualified to 12,000 psi (82.7 MPa)

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2.11 Cementing:

2.11.1 FUNCTIONS OF CEMENT: In an oil/ gas well, the primary functions of cement are: 1. Provide zonal isolation 2. Support axial load of casing strings 3. Provide casing support and protection against corrosive fluids 4. Support the borehole

Cement is made from calcareous and argillaceous rocks such as limestone, clay and shale and any other material containing g a high percentage of calcium carbonate. The dry material is finely ground and mixed thoroughly in the correct proportions. The chemical composition is determined and adjusted if necessary. This mix is called the kiln feed. The kiln feed is then heated to temperatures around 2600-2800 F (1427-1538 C). The resulting material is called clinker. the clinker is then cooled, ground and mixed with a controlled amount of gypsum and other products to form a new product called Portland cement. Gypsum (CaSO4. 2H2O) is added to control the setting and hardening properties of the cement slurry. Cement slurry is the mixture produced when dry cement is mixed with water. Oil well cement is manufactured to API Specification 10 and is divided into 8 classes (A-H) depending upon its properties. Class G and H are basic well cements which can be used with accelerators and retarders to cover a wide range of depths and temperatures. The principal difference between these two classes is that Class H is significantly coarser than Class G. Additional chemicals are used to control slurry density, rheology, and fluid loss, or to provide more specialised slurry properties. Additives modify the behaviour of the cement slurry allowing cement placement under a wide range of downhole conditions.

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Over 100 additives for cement are available and these can be classified under one of the following categories:

2.11.3 Slurry testing:

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2.11.4 Classification Criteria: 2.11.4.1 API Classification System:

Specifications for well cements were established by the API, because the conditions to which Portland cement is exposed in wells can differ radically from those experienced in construction applications. There are currently nine classes of API Portland cements, designated A through J. They are arranged according to the depths, to which they are placed, and the temperatures and pressures to which they are exposed. 2.11.4.2 Classes and types of cement: The API has classified nine types of cement, depending on depth, and conditions of hole to be cemented these are as follows;

2.11.5 Cement placement techniques: 2.11.5.1 Primary cement job The method of doing this is to pump cement down the inside of the casing and through the casing shoe into the annulus. This operation is known as a primary cement job. A successful primary cement job is essential to allow further drilling and production operations to proceed.

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2.11.5.2 Secondary or squeeze cement job: A secondary cement job may be performed for many reasons, but is usually carried out on wells which have been producing for some time. They are generally part of remedial work on the well (e.g. sealing off water producing zones or repairing casing leaks). These cement jobs are often called squeeze cement jobs because they involve cement being forced through holes or perforations in the casing into the annulus and/or the formation.

2.11.6 Methods of Cementing: 2.11.6.1 Single Stage Cementing: Is normally to cement conductor and surface pipes. A single batch of cement is prepared and pumped down the casing. It should be noted that all the internal parts of the casing tools including the float shoe, wiper plugs, etc. are easily drillable.

2.11.6.2 Multi stage Cementing It is employed in cementing long casing string in order to reduce the total pumping pressure, reduce the total hydrostatic Pressure on weak formations There preventing Their fracture, allow of selective cementing of formations and ensure effective Cementing around the shoe of the previous casing string. In multistage cementing a stage cementer is installed at a selected position in the casing string, the position of the stage cementer is dictated by the total length of the cement column and the strength of formations.

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2.11.6.3 Liner Cementing The liner is a short string of casing, which does not reach to the surface. It is hung from the bottom of the previous casing string by use of a liner hanger. The liner is run on drill pipe and cemented by pumping the cement slurry through the drill pipe and liner and finally displacing it behind the liner to Just above the liner hanger.

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2.11.7 Casing and cementing accessories:

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2.11.8 cementing design: 1- Requirment needed for design:

2- design steps:

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3- basic data :

4-Liner casing cementing design:

Because the production casing is set at depth of 6500 ft., so the cement class that will be used is (class G) that intended to be used at depth in the range of 8000-1000 ft. in conditions that require moderate strength, temperature, and pressure with the ability of adding additives or can be used as manufactured.

Properties of two types of cement (lead and tail)

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2.11.8.1 Calculations of two types of cement:

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We calculate the hydrostatic pressure at the shoe of the casing considering the presence of cement into the annulus and neglecting the presence of any displacement fluid into the casing as a safety factor and compare this value with the fracture pressure of the formation and the collapse pressure value of the casing. â&#x20AC;˘ Then you should determine if you need a one stage or two stage cementing

P hydrostatic is lower than the collapse pressure and the fracture pressure so we donâ&#x20AC;&#x2122;t need a 2 stage cementing

A multi-stage collar (or DV tool) It is used to allow the casing to be cemented in two stages to prevent weak formations being subjected to excessive hydrostatic pressure of long cement columns .The tool is actually a small section of casing with the same strength properties as the remaining string. The tool has two internal sleeves and openings which are covered by the lower sleeve. The lower sleeve is opened by dropping a bomb which pushes the sleeve down and uncovers the holes. This allows the cement to be pumped through the casing and the holes in the stage collar and placed around the casing. When the required volume of cement is pumped, the holes are closed by dropping a closing plug which pushes an upper sleeve downward to cover the holes in the stage collar.

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Dv tool

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Calculations of the lead cementing type

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Calculations of the Tail cementing type

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Cement calculations by using Cement job analyzer software

Cost analysis for the two scenarios

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The cost of sacks is the same in two scenarios so this point is out of consideration. Assuming

Surface Casing Cementing Design

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2.12 Drill String Design: 2.12.1 Introduction:

The drill string is the mechanical linkage connecting the drill bit at the bottom of the hole to the rotary drive system on the surface. The drill string serves the following

Functions: 1. Transmits rotation to the drill bit 2. Exerts weight on the bit; the compressive force necessary to break the rock 3. Guides and controls the trajectory of the bit; and 4. Allows fluid circulation which is required for cooling the bit and for cleaning the hole. 2.12.2 Components of the drill string: •Drill Bits • BHA; It includes: • Drill collars • Heavyweight (walled) drill pipes (HWDP) • Stabilizers • Reamers • Jars • Shock-subs • X-overs • MWD-LWD • Drill pipes • Top drive or (Kelly, Kelly bushing, Rotary table, Swivel)

2.12.3 Drill pipes: • The heavy seamless tubing used to rotate the bit and circulate the drilling fluid. Manufactured in three ranges:

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2.12.3.1 DRILL PIPE GRADE: The grade of drill pipe describes the minimum yield strength of the pipe, API defines five grades: D, E, X, G and S. However, in oil well drilling, only grades E, G and S are actually used. In most drill string designs, the pipe grade is increased if extra strength is required.

2.12.3.2 DRILL PIPE CLASSIFICATION: Drill pipe, unlike other oilfield tubulars such as casing and tubing, is re-used and therefore often worn when run. As a result the drill pipe is classified to account for the degree of wear. The API has established guidelines for pipe classification in API RP7G. A summary of the classes follows.

NOTES

A drill pipe joint is an assembly of three components: drill pipe with plain-ends and a tool joint at each end. One tool joint acts as the pin and the other acts as the box. All API tool joints have minimum yield strength of 120,000 psi regardless of the grade of the drill pipe itself. API sets tool joint torsional strength at 80% of the tube torsional strength and the makeup torque is 60% of the tool joint torsional capacity.

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Here in Egypt, the most common drill pipe grades used in, roughly, all the drilling rigs are G and S for sizes of 5â&#x20AC;? and 3.5â&#x20AC;?.

Drill collars are the predominant component of the bottom hole assembly. Drill collars are used to provide weight for use at the bit and at the same time keep the drill pipe in tension. Drill collars have a significantly greater stiffness when compared to drill pipe and as such can be run in compression. Drill pipe, on the other hand will tend to buckle when run in compression. Repeated buckling will eventually lead to early drill pipe failure by fatigue. In practice, buckling will not occur if weight on bit is maintained below the buoyed weight of the collars. WOB should not exceed 85% of the buoyed weight of the collars. The remaining 15% of drill collar weight is placed in tension. This ensures that the neutral point is in the drill collars and that the drill pipe is always in tension. When drilling highly deviated, extended reach or horizontal wells, computer modeling of torque and drag should be used for establishing grades, size and weight of drill and coupling to be used. On such wells, calculation of the effects of deviation on predicted torque and drag are too complicated to calculate manually.

Slick Drill collars

Have the same nominal outside diameter over the total length of the joint

Spiral Drill collars

Used primarily to reduce the risk of differential sticking. The spirals reduce the weight of the collar by only 4 -7% but can reduce the contact area by as much as 50%.

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2.12.5 The criteria of drill string design: 1. Collapse 2. Tension 3. Dogleg Severity Analysis Burst pressure is not considered in drill string design due to the fact that burst loads and back-up loads are provided by the same fluid in the well. Therefore, under normal circumstances there are no effective burst loads, except during squeeze operations where surface pressure is applied. If squeeze pressures are high, a back-up annulus pressure would normally be applied to reduce the effective burst pressure. Collapse and tension considerations are used to select the pipe weights grades and couplings. Slip crushing affects the tension design and pipe selection. Dogleg analysis is performed to study the fatigue damage resulting from rotation in doglegs. Doglegs analysis may not affect the selection of the pipe; however, it will assist in determining the maximum permissible dogleg during any section of the well.

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2.12.5.1 Collapse design: The criteria to be used as a worst case for the collapse design of drill pipe is typically a DST. The maximum collapse pressure should be determined for an evacuated string, with mud hydrostatic pressure acting on the outside of the DP. Use of this criterion also accounts for incidence of a plugged bit or failure to fill the string when a float is used during trips into the hole . A design factor is used in constructing the collapse design line. The design factor to be used for this full evacuation scenario is 1.0. Collapse Calculations 1) Drill Stem Testing (DST): The maximum differential pressure across the drill pipe which exists prior to the opening of the DST tool is given by:

where

2) Design Factor in collapse: A DF of 1.125 is normally used.

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2.12.5.2 Tension Design: The tension load is evaluated using the maximum load concept. Buoyancy is included in the design to represent realistic drilling conditions.

1) TENSILE FORCES: 1. Weight carried: The greatest tension (P) on the drill string occurs at the top joint at the maximum drilled depth, see Figure. This is given by:

where

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- P is the total weight of the submerged drill string. It is highly dependent on mud weight - The higher the mud weight the less weight seen at surface on the Martin Decker weight indicator. The influence of mud weight is shown through the term BF (buoyancy factor) - The drill string should not be designed to its maximum yield strength to prevent the drill pipe from yielding and deforming. At yield, the drill pipe will have: • Deformation made up of elastic and plastic (permanent) deformation • Permanent elongation • Permanent bend and it may be difficult to keep it straight To prevent the drill pipe from yielding and deforming, API recommends that the use of maximum allowable design load (Pa), given by:

From the previous equations we obtain

where

The Margin of Over pull is the minimum tension force above expected working load to account for any drag or stuck pipe. The MOP is usually of the order of 100,000 lbs. 2. SHOCK LOADING: The additional tensile force generated by shock loading is given by:

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3. Bending: The additional tensile force generated by bending is given by:

Where

2) Design FACT0R: A design factor of 1.6 should be applied to the tension loads calculated above if shock loading is not accounted for. If the shock loading is quantified and included in the load calculation, a design factor of 1.3 can be used. 3) Slip Crushing: The maximum allowable tension load must also be designed to prevent slip crushing of the pipe. In an analysis of the slip crushing phenomena Reinhold and Spini proposed an equation to calculate the relationship between the hoop stress caused by the action of the slips and the tensile stress in the pipe resulting from the load of the pipe hanging in the slips. The equations used are as follows:

2.12.6 Drill Collar Design: Step 1

where

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Step 2

2.12.7- Drill pipe design Step 1

The outside diameter of the drill pipe is selected according to the borehole size from the drilling data handbook and also the inner diameter.

Step 2

Step 3

Step 4

Select of drill pipe grade

Step 5

Check for collapse:

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Step 6

Step 7

Repeat the previous procedure for every bit size run in the hole

Design

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Design of d/c drill collar 1 â&#x20AC;&#x201C; Calculation of buoyancy factor:

2-Length of D/C and number of joints:

Step 1

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Step 2

Selecting the grade for drill pipe

Step 3

Check for Collapse and determine MOP

Note

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2.13 Directional Drilling: 2.13.1 The Optimum Well Plan Applying Directional Drilling Technique: In the early days of land drilling most wells were drilled vertically, straight down into the reservoir. Although these wells were considered to be vertical, they rarely were. Some deviation in a wellbore will always occur, due to formation effects and bending of the drill string. It had been the practice to build jetties out into the ocean and build the drilling rig on the jetty. However, this became prohibitively expensive and the technique of drilling deviated wells was developed. Since then many new techniques and special tools have been introduced to control the path of the wellbore. An operating company usually hires a directional drilling service company to: • provide expertise in planning the well; • supply special tools • to provide onsite assistance when operating the tools.

1- Multiple wells from artificial structures: Today’s most common application of directional techniques is an offshore drilling where an optimum number of wells can be drilled from a single platform. This operation greatly simplifies production techniques and gathering systems, a governing factor in the economic feasibility of the offshore industry. 2- Fault drilling: Another application is in fault control where the wellbore deflected across or parallel to the fault for better production. This eliminates the hazard of drilling a vertical well through a steeply inclined fault plane, which could slip and shear the casing. 3- Inaccessible locations: The same basic techniques are applied when an inaccessible location in a producing zone dictates remote rig location, as in production located under riverbeds, mountains, cities, etc. 4- Sidetracking and straightening: This is used as a remedial operation, either to sidetrack an obstruction by decimating the wellbore around and away from the obstruction, or to bring the wellbore back to vertical by straightening out cooked holes. 5- Salt dome drilling: Directional drilling programs are also used to overcome the problems of salt dome drilling, to reach the producing formations, which often lie underneath the overhanging cap of the dome. 6- Relief wells: Directional drilling was first applied to this type of well so that mud and water could be pumped in to kill a wild and cratered well. 141

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Multiple wells from offshore structures

Fault Drilling

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Inaccessible location

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Controlling a Vertical Well

Salt dome drilling

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Relief Well

Reasons for directional drilling

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2.13.3 CONSIDERATIONS WHEN PLANNING THE DIRECTIONAL WELL PATH: When planning a directional well a number of technical constraints and issues will have to be considered. These will include the:

2.13.3.1 Target location: The location of the target is chosen by the geologists and/or the reservoir engineers. The target location will be specified in terms of a geographical co-ordinate system such as longitude and latitude or a grid co-ordinate system such as the UTM (Universal Transverse Mercator) system. The grid reference system, In which the coordinates are expressed in terms of feet (or meters) north and east of a local or national reference point, is particularly useful when planning the directional well path, since the displacement of all points on the well path can be easily calculated. 2.13.3.2 Target size and Shape: The size and shape of the target is also chosen by geologists and/or reservoir engineers. The target area will be dictated by the shape of the geological structure and the presence of geological features, such as faults. In general, the smaller the target area, the more directional control that is required, and so the more expensive the well will be. 2.13.3.3 Rig location: The position of the rig must be considered in relation to the target and the geological formations to be drilled (e.g. salt domes, faults etc.). If possible the rig will be placed directly above the target location. When developing a field from a fixed platform the location of the platform will be optimized so that the directionally drilled wells can reach the full extent of the reservoir. 2.13.3.4 Subsurface obstacles: Drilling close to an existing well can be very dangerous, particularly if the existing well is on production. This is especially true just below the seabed on offshore platforms, where the wells are very closely spaced. The proposed well path must be designed so that it avoids all other wells in the vicinity. It is essential that the possible errors in determination of the existing and proposed wells are considered when the trajectory of the new well is designed. 146

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2.13.3.5 Geological Sections: The equipment and techniques involved in controlling the deviated well path are not suited to certain types of formation. It is for example difficult to initiate the deviated portion of the well (kickoff the well) in unconsolidated mudstone. The engineer may therefore decide to drill vertically through the problematic formation and commence the deviated part of the well once the well has entered the next most suitable formation type. 2.13.3.6 Casing and Mud program: The trajectory of the well will be designed so that the most difficult parts of the well are drilled through competent formations, minimizing problems whilst drilling the well. It is very common to initiate the kick-off just below the surface casing and possibly to change out to oil-based mud when drilling the build-up section. In highly deviated wells the build-up section of the well may also be cased off before drilling the long, tangent section of the well. Oil-based mud may also be used in the long tangent sections of the well. The trajectory of the well will therefore be designed so that these operations correspond to the casing setting depths which have been selected for many other reasons. This is an iterative process taking into account all of the considerations when designing the well.

2.13.4 Basic hole patterns:

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Short kickoff point

Medium kickoff point

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Long kickoff point and build 2.13.5 Deflection tool: A prime requirement for directional drilling is suitable deflection tools, along with special bits and other auxiliary tools. A deflection tool is a mechanical device that is placed in the hole to ensure a drilling bit to be deviated from the present course of the hole. There are numerous deflection tools available for deflecting a hole or correcting direction. The most common tools used for deflection

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2.13.5.1 Whip Stocks: The whip stock was the main deflection tool from 1930-1950. A standard whip stock is seldom used nowadays, but it has not disappeared completely. Whip stocks are used in coiled tubing drilling for re-entry work.

1) Standard (removable) Whip stock: The Standard Removable Whip stock is mainly used to kick off wells, but can also be used for sidetracking. It consists of a long inverted steel wedge which is concave on one side to hold and guide the drilling assembly. It is also provided with a chisel point at the bottom to prevent the tool from turning, and a heavy collar at the top to withdraw the tool from the hole. It will usually be used with a drilling assembly consisting of a bit, a spiral stabilizer, and an orientation sub, rigidly attached to the whip stock by means of a shear pin. 2) Circulating Whip stock: The “Circulating Whip stock” is run, set and drilled like the standard whip stock. However, in this case the drilling mud initially flows through a passage to the bottom of the whip stock which permits more efficient cleaning of the bottom of the hole and ensures a clean seat for the tool. It is most efficient for washing out bottom hole fills. 3) Permanent Casing Whip stock: The “Permanent Casing Whip stock” is designed to remain permanently in the well. It is used where a “window” is to be cut in casing for a sidetrack. The casing whip stock can be set using a Baker Model “D” Packer. A special stinger at the base of the whip stock slips into the packer assembly, and a stainless steel key within the packer locks the whip stock’s anchor-seal and prohibits any circular movement during drilling. The normal procedure is to orientate the system and then set the packer. After this, the starting mill is pinned to the whip stock and the whole assembly run slowly in hole and seated in the packer. 150

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2.13.5.2 Jetting: Jetting (or badgering) is a technique used to deviate wellbores in soft formations. Although jetting has subsequently been supplanted by down-hole motor deflection assemblies it is still used frequently and offers several advantages which makes it the preferred method in some situations. A special jet bit may be used, but it is also common practice to use a standard soft formation tri-cone bit, with one very large nozzle and two smaller ones. 1) Requirements for jetting: The formations must be soft enough to be eroded by the mud exiting the large nozzle. As a rough rule of thumb, if formations cannot be drilled at penetration rates of greater than 80 ft. /hr. using normal drilling parameters, they are not suitable for jetting. Jetting is most effective in soft, sandy formations, and its effectiveness is reduced as depth increases, since the formations become more compacted. 2) Nozzling the Jetting Bit: There are three alternatives: â&#x20AC;˘ Use a specialized jet bit with a large extended nozzle in place of one of the cones. â&#x20AC;˘ Fit one large and two small nozzles in a conventional tri-cone bit. â&#x20AC;˘ Blank off one nozzle of a conventional bit to divert the flow through the other two.

Jet bit

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Jetting procedure

Advantages of Jetting • It is a simple and cheap method of deflecting well bores in soft formations. No special equipment is needed. • Dogleg severity can be partly controlled from surface by varying the number of feet “jetted” each time.

Disadvantages of Jetting • The technique only works in soft formation and therefore at shallow depths. For this reason, jetting is mainly used to kick wells off at shallow depths. • In jetting, high dogleg severities are often produced. Deviation is produced in a series of sudden changes, rather than a smooth continuous change. For this reason, it is normal practice to jet an under gauge hole and then open it out to full gauge, which smoothes off the worst of the doglegs.

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2.13.5.3.Down hole motor and bent sub: A common method of deflecting wellbores is to use a down hole motor and a bent sub. The bent sub is placed directly above the motor and the bent sub which makes this a deflection assembly. Its lower thread (on the pin) is inclined 1Â° - 3Â° from the axis of the sub body. The bent sub acts as the pivot of a lever and the bit is pushed sideways as well as downwards. This sideways component of force at the bit gives the motor a tendency to drill a curved path, provided there is no rotation of the drill string. The degree of curvature (dogleg severity) depends on the bent sub angle and the OD of the motor, bent sub and drill collars in relation to the diameter of the hole. It also depends on the length of the motor.

Structure of down hole motor

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Components of PDM 2.13.5.4 Steerable Drilling Systems: A steerable drilling system allows directional changes (azimuth and/or inclination) of the well to be performed without tripping to change the BHA, hence its name. It consists of: a drill bit; a stabilized positive displacement steerable mud motor; a stabilizer; and a directional surveying system which monitors and transmits to surface the hole azimuth, inclination and tool face on a real time basis. The capability to change direction at will is made possible by placing the tilt angle very close to the bit, using a navigation sub on a standard PDM. This tilt angle can be used to drill in a specific direction, in the same way as the tilt angle generated by a bent sub with the drill bit being rotated by the mud motor when circulating. When rotating from surface we will of course be circulating fluid also and therefore the rotation of the bit generated by the mud motor will be super-imposed on the rotation from surface. This does not alter the fact that the effect of the bit tilt angle will be eliminated by the rotation of the entire assembly.

Steerable drilling system

2.13.6 Types of directional surveys: Directional measurements can be obtained from a variety of surveying instruments. The following are the most commonly used by industry present:

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Magnetic Single Shot The single shot magnetic survey tool records one inclination and direction per run. This tool can be dropped in drill pipe or run on wire line. It must be landed in non-magnetic pipe or run on wire line in open hole. It cannot be used in a regular steel drill string. Magnetic Multi-shot The magnetic multi-shot have the same compass units as the single shot and differ only in the camera unit. The multi-shot use a reel of film, which is advanced by a present timer. The same principles stated about the single shot are also applicable to the multi-shot. Single Shot Gyroscopic The Single Shot Gyro survey tool records one inclination and direction per run. The tool must be run on a wire line. The single shot gyro relies on a motor-driven gyroscope rather than a compass. The gyro can be run inside regular steel collars or in close proximity to other steel members such as casting or another conductor pipe. Gyroscopic Multi-shot Survey The gyroscopic multi-shot is similar to the magnetic tool with the exception it relies on a motor-driven gyroscope rather than a compass. For this reason, the Gyro can be run inside regular steel drill collars, drill pipe, tubing, and casting. This tool is run on a wire line and is stopped at preselected survey intervals.

Note

The previously mentioned tools are the most common surveying instruments used in directional wells. They are also periodically used in straight holes. Other instruments that can measure inclination and direction are the Sperry-Sun Steering Tool and Scientific control drilling Tool, plus the directional log that is run by most logging companies.

2.13.7 Directional Drilling Design: By using build and hold trajectory The given data is:

• Kick Of Point(K.O.P)(D1) • Build Up Rate(B.U.R) • Total vertical Depth (D3) • Displacement @ T.D(X3) • L1: Length of A.R.C(ft). • MD1: The Measured depth to the end of build(ft). • MD2: Total Measured Depth(MD2)(ft). • X2 : The Horizontal Departure to the End of Build(ft).

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Drilling

The Design of the trajectory

2-Maximum inclination angle(Î&#x2DC;):

3-Length of A.R.C:

4-The Measured depth to the end of build(MD1):

5- Total Measured Depth(MD2):

6- The Horizontal Departure to the End Of Build(X2): 7-T.V.D at end of build (D2):

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2.14 Drilling Rig: 2.14.1 Elements of drilling rig:

1. Crown Block and Water Table 2. Cat line Boom and Hoist Line 3. Drilling Line 4. Monkey board 5. Traveling Block 6. Top Drive 7. Mast 8. Drill Pipe 9. Doghouse 10.Blowout Preventer 11.Water Tank 12.Electric Cable Tray 13.Engine Generator Sets

14.Fuel Tank 15.Electrical Control House 15.Electrical Control House 16.Mud Pumps 17.Bulk Mud Component Tanks 18.Mud Tanks (Pits) 19.Reserve Pit 20.Mud-Gas Separator 21.Shale Shakers 22.Choke Manifold 23.Pipe Ramp 24. Pipe Racks 25.Accumulator

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Components of modern rotary drilling rig

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2.14.2 Components of drilling rigs:

2.14.2.1 Hoisting System : The hoisting equipment system consists of: 1- The derrick or the mast 2- The draw-works. 3- The crown-block. 4- The traveling block. 5- The wire rope. 6- The hook. 1) The Derrick: It is a tapered tower made of steel which serves to suspend the drill string or casing strings or place drill pipe stands during housing operations (round trips) . 2) The draw-works: Is the main item of any drilling rig. It serves as the power control center of the rig. The power plant of the rig supplies motive power to the hoisting drum, permitting reeling and unreeling of the drilling line.

DRAWWORKS

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3) Crown block: The crown block Is mounted on the top of the derrick. it is the stationary block of the block and tackle system. Crown Block contains a number of sheaves on whiis wound the drilling line. The crown block provides a means of taking the drilling line from the hoisting drum to The travelling block. 4) The travelling block: The travelling block is the moving block of the system and suspended from the loops of the wire rope which passes over all the sheaves of the two blocks one after another. a diamond-shaped block containing a number of sheaves which is less than those in the crown block.

Travelling block Crown block 5) The rotary hook: The rotary hook Is suspended beneath the traveling block from its bail. The function of the hook is to suspend the swivel, an elevator, while drilling, or making round trips

Block and tackle arrangement 2.14.2.2 Rotary system: The rotary system is intended for transmitting the rotary to the drill string to which lower end a drilling bit is attached. The rotary system consists of: 1. The rotary table or the top drive system ( TDS). 3. The kelly 2. The swivel. 5. Drill pipe and Drill collars 4. Bits.

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1) The Rotary Table: The rotary table is situated in the center of the derrick floor, its function is to rotate the drill string in the process of drilling and serve as a support for the drill string while round trips are being made. 2) Top drive: In the top drive system Power swivel or power-sub installed just below a conventional swivel can be used to replace the Kelly, Kelly bushing & rotary table Drilling rotation is achieved through hydraulic motor incorporate in the power swivel or power sub. 3) The Swivel: Swivel is probably the most ingenious element of the drilling rig. While drilling is in progress, the swivel is suspended from the hook and suspends the whole weight of the drill string. It permits free rotation of the drill string and serves as the passageway for the drilling fluid from the hose lo the drill string, which is rotated. 4) Drill pipe: Is the major portion of drill string, it is specified by its outer diameter, weight per foot, steel grade& range length. 5) Drill collar: Is the lower section of drill string it is a heavy thick wall steel tubular. 6) Drill bit: Is used to disintegrate the rock, Types is (mechanical bit and polycrystalline diamond bit).

Different components of rotating system

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Top Drive

Types of bits

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2.14.2.3 Slush (or Mud) pumps: Usually a drilling rig is provided with two slush pumps. Their function is to circulate drilling fluid in the process of drilling. The heart of the circulating system is the mud pumps. There are two types of pumps used in the oil industry: Duplex and Triplex.

Mud pumps 2.14.2.4 Prime movers and transmissions: The prime movers and transmissions are necessary to provide motive power for all the mechanics of the rig, the hoisting system, the rotary system and the mud pumps.

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2.14.2.5 Drilling fluid circulating system: Consists of mud pits and tanks, an auxiliary pump and mechanisms for mixing, chemical treatment and solids controls of the drilling fluid (a mud hopper, a shaker, a hydro cyclone ( etc.)

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2.14.2.6 Well control system: The well control system is used to prevent the uncontrolled flow of formation fluids from the wellbore when the bit penetrates a permeable formation which is pressurized formation. 1) Type of BOPâ&#x20AC;&#x2122;s: A) Annular preventer: Stop the flow from the well using a ring of synthetic rubber that contract in the fluid passage in annulus.

Annular type blowout preventer B) Ram preventer: Have two packing element on opposite sides that close by moving toward to each other (pipe ram, blind ram shear ram).

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BOP Stack and choke manifold 2.14.2.7 Well monitoring system: The well monitoring equipment system use devices to display different parameters and factors that must be measured continuously during the drilling operations that are: 1. Penetration Rate 2. pump rate 3. Depth 4. pump pressure 5. Hook load 6. Mud salinity 7. Rotary torque 8.Mud density 9. Gas content 10. Pit level 11. Mud temperature 12. Rotary speed.

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Well monitoring system results 2.14.3 Calculation for Well Gawaher N- 4: Maximum Working Loads • For 8 ½ Hole Section Max casing Weight= 83680 lb. Max Drill string Weight= 135783 lb.

• For 12 ¼ Hole section Max casing Weight= 102708 lb. Max Drill string Weight= 60462 lb.

So the Maximum Working load is The Weight of Drill string in 8 ½ Hole Section. So we will design For load = 135783 lb. = 62 tons 1 - kelly selection: It has always been a good practice, when the hole or casing size permits, to use a kelly one size larger than the drill pipe string. The most popular size of kelly in use today is the 5 ¼” hexagonal kelly and its specifications are:

From the previous table we prefer to use a hexagonal type and we have drill pipe with 5 in so we select 5 ¼ in Kelly

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2- Swivel Selection Dead load capacity= Wb+Wd/c+Wd/s + Kelly weight W= 80 + 135783+ 1815.46= 137679 lb =62.5 tons

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Drilling Data Handbook, Brantlyâ&#x20AC;Ś We will select the following rotary hydraulic swivel depending upon economics and safety considerations:

3- Hook Selection: Hook is selected according to the maximum weight that will be supported either during drilling or lowering the casing. Max. weight =Drill String wt. + Kelly+ Swivel wt Maximum weight= 135783 +1815.46+ 1850 =140000 lb. = 63.6 tons We will select our hook depending upon the highest load. From Sovonex Tech (A supplier provides Hooks and Blocks) we will choose HK90. Hook specification Maximum Hook load = 900 KN Weight = 1800 kg = 3969 lb. 169

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4-Load supported by Crown Block: Max. weight =Drill String wt. + Kelly wt+ Swivel wt +Hook weight Max. Weight = 135783 +1815.46+ 1850+3969= 144000lb. =65.4 tons 35% is a safety factor added due to friction and drag forces Max. Weight = 194400 lb. = 89 tons Â Final Results Design for the maximum derrick load = 194400 lb. = 89 ton. Note for wind load, Wind load = .004 V^2 lb. An actual wind velocity of 54 to 70 mph is determined by the Robinson Four Cup Anemometer.

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5-Hoisting system selection: 1. For maximum traveling block load: The most common and widely used travelling block for drilling rigs has 6 sheaves Considering the Maximum weight = HL max + W Hook For maximum traveling block load = Hook load +Hook wt. =140000+3969= 144000 lb. = 65.5 tons We will select the following travelling block depending upon economics and safety considerations.

2. For hoisting cable design: Consider the maximum tension in the line in pounds, which expected for the drilling operation

Tf.l= 144000/(12*.782) = 15346 lb. = 6.97 tons Multiply this tension by (3) as safety factor to obtain the safe ultimate strength of the required cable. Tf.l= 21 tons

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From Drilling Data Handbook, select the cable which has the closest ultimate strength and has the suitable diameter for hoisting sheaves

Deadline-load is given by:DL

3-For Crown block design: The number of sheaves of crown block will increase by one over the number of sheaves of the travelling block. Sheaves of C/B = Sheaves of T/B + 1. Total crown block load T.C.L = T.B. load + T.B. weight + F.L. tension + D.L. tension. = 144000+16105+15346+14882=190333 lb. =86.4 ton From Drilling Handbook

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4-Draw-works design: • As a rule of thumb, the draw works should have 1 hp. for every 10 ft. drilled… • In another words, for drilling 5000 ft., Draw works should have 500 hp. Assume (normally and common values) Hook and block speed Vw = 120 ft./min Mechanical efficiency of the draw work = 0.88 EF = 0.782 (for 12 lines) Power requirements for draw works

So, we will select a motor with 1000 hp rating. From Drilling Data Handbook, Brantly , We will select the following drilling line depending upon economics and safety considerations

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2.14.4 Ton Miles of Drilling Line: The drilling line, like any other drilling equipment, does work at any time it is involved in moving equipment in or out of the hole. The amount of work done varies depending on the operation involved. This work causes the wire line to wear and if the line is not replaced it will eventually break. The reader should note that the drilling line can only contact a maximum of 50% of the sheaves at any one time, but the damage will be done on the contact area any way. The amount of work done need to be calculated to determine when to change the drilling line. The following gives equations for calculating the work done on the drilling line: 1. Work done in round trip operations (Tr)

2. Work done in casing operations (Ts)

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3. Ton mile during coring

4. Ton mile during drilling a section of a hole

3. The length of the wire rope to be wrapped on the drum: From Drilling Hand Book, Select drum with the following specifications

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2.14.5 Derrick efficiency factor DEF: It is the measure of the degree of distribution of the loads on four legs and it is obtained by dividing the actual crown block load by the maximum equivalent load for each leg. 1. Position of dead line anchor:

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Different positions of dead line anchor

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The relationship between N & DEF

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2.15 Mud Circulation System: The figure below gives a schematic of the circulating system. We shall divide the circulating system into four sections:

Our objective is to calculate the pressure (energy) losses in every part of the circulating system and then find the total system losses. This will then determine the pumping requirements from the rig pumps and in turn the horse power requirements.

Pressure loss along the pass of mud 2.15.1 SURFACE CONNECTION LOSSES (P1): Pressure losses in surface connections (P1) are those taking place in standpipe, rotary hose, swivel and Kelly. The task of estimating surface pressure losses is complicated by the fact that such losses are dependent on the dimensions and geometries of surface connections. these dimensions can vary with time, owing to continuous wear of surfaces by the drilling fluids. The following general equation may be used to evaluate pressure losses in surface connections:

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In practice, there are only four types of surface equipment; each type is characterized by the dimensions of standpipe, kelly, rotary hose and swivel. These tables summaries the four types of surface equipment.

2.15.1 SURFACE CONNECTION LOSSES (P1): Drill bits are provided with nozzles to provide a jetting action, mainly required for cleaning and cooling, but can also help with rock breakage in soft formations. The largest nozzle is one inch in size, often termed open, but more often the nozzles used are a fraction of an inch. Hence, the pressure requirements to pass, say 1000 gpm, through such small nozzles will be large. For a given length of drill string (drill pipe and drill collars) and given mud properties, pressure losses P1, P2, P3, P4 and P5 will remain constant. However, the pressure loss across the bit is greatly influenced by the sizes of nozzles used, and volume flow rate For a given flow rate, the smaller the nozzles the greater the pressure drop and, in, turn the greater the nozzle velocity.

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2.15.3 PIPE AND ANNULAR PRESSURE LOSSES: Pipe losses take place inside the drill pipe and drill collars and are designated in the previous figure as P2 and P3, respectively. Annular losses take place around the drill collar and drill pipe and are designated as P4 and P5. The magnitudes of P2, P3, P4 and P5 depend on: 1-Dimensions of drillpipe (or drill collars), e.g. inside and outside diameter and length. 2-Type of flow, which can be laminar, or turbulent. 3-Mud rheological properties, which include mud weight, plastic viscosity and yield point. Three models will be discussed: Bingham Plastic, Power law and Herschel- Bulkley. These models approximate the annulus as two parallel plates, with the effects of rotation being ignored. In this project the Power law and Bingham Plastic models will be used to calculate the annular pressure losses. They are chosen primarily because they are widely applied in the oil drilling industry. Bingham Plastic Modelâ&#x20AC;Ś The Bingham Plastic model describes laminar flow using the following equation

Where

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The values of YP and PV are calculated using the following equations:

Bingham Plastic Model The slope of a line connecting any point on the straight line to the origin is described as the apparent viscosity at that particular shear rate. The Bingham Plastic model usually over-predicts yield stresses (shear stresses at zero shear rate) by 40 to 90 percent. The following equation produces more realistic values of yield stress at low shear rates:

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2.15.4 Calculation of pressure losses: Given That:

For pressure losses during circulation. 1-Pressure losses due to surface connections:

We will choose surface equipment type (2) as we have a kelly of 40’ long and 2.25” ID and a hose of 55’ long and 2.5” ID due to swivel ID. ∆PS = 9.6 *10-5 * 9.8^.8 * 450^ 1.8 * 20^ 0.2 = 65 psi 2-Pressure losses inside Drill pipes:

3-Pressure losses inside Drill collars:

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â&#x2C6;&#x2020;PIDc= 590 psi 4- Pressure losses outside Drill collars:

â&#x2C6;&#x2020;PODc = 42 psi 5- Pressure losses outside Drill pipes:

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6-Pressure losses across the drill bit: Cone bit has 3 nozzles of size 13/16, in. with bit nozzle co-efficient C = 0.97

Total pressure drop calculations

2.15.5 Mud pump Horse power calculations:

Where

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â&#x20AC;˘ We suppose to use two pumps to give the needed horse power in the manner that one on operations and one standby Note That: â&#x20AC;˘ If one pump is not Suffient to give the required horse power, we are supposed to use three pumps to make one standby

2.16 Pressure Control (BOP Selection): The safest procedure for designing preventer pressure ratings is to ensure that the preventer can withstand the worst pressure condition possible. This condition occurs when all drilling fluids have been evacuated from the annulus and only low density from fluids such as gas remain, so, in other words a kick from reservoir while the first line of defense not exist (the drilling mud) The pressure imposed on the preventer would be the difference between formation pressure and gas hydrostatic pressure. Maximum formation pressure

Determine

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1-Selection of flanges:

schematic illustration of casing and wellhead body 2 â&#x20AC;&#x201C; Selection of bolts:

3- Selection of (Bop): Use Cameron ram type BOP, Operating Data:

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Selection of Cameron type D Blow-out preventor:

4. Hydril annular BOP:

5. Selection of KOOMEY Ram Type

10-Average penetration rate Each formation is drilled by one bit or more. The average penetration rate is calculated by the following equation

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Drilling summary

2.17 Calculating average Penetration Rate:

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Drilling

Total Drilling Time = 182 hours ROP will decrease in hard formations

Average penetration rate of different formations

Rotating time Vs. depth

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Drilling

Time for pulling one stand is not a constant and it should be Controlled to not cause swabbing so you should be careful Especially if you have: – Balled bit/BHA – Viscous mud – Narrow annulus

Trip time Vs. depth

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Cumulative time Vs. depth

2.19 Total Drilling Cost: The drilling cost can be calculated from the following equation

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2.20 Drilling problems: In our well no problems have been found but we will talk generally about drilling problems in petroleum field. 1.Lost of Circulation: Are expected while drilling in hole, through the unconsolidated sand of Miocene and Abu-Roash formation.

Remedy

- Conventional plugging materials or suitable LCM can successfully control this kind of losses. So, we are supposed to cover Abu-Roash formation by the casing before drilling Khoman formation because Khoman formation needs higher mud weight than the needed in AbuRoash formation, So by doing that we avoid mud loss that encountered from the lowest mud weight

2. Over pressure: Is expected while drilling 13 3/8 `` hole in bottom Abu-Roash and top Khoman formation, especially if high-pressure water flow encountered reaching value 1.8 to 1.9 kg/lit. Remedy

it is recommended that to control well with mud weight 1.82 to 1.92 kg/lit.

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3. Differential sticking: It might be encountered while drilling depleted sand zones

Remedy

-This type of problem can be avoided by keeping string always in motion and reducing as low as possible the number of drill collar in the BHA or by using spiral drill collars. -In addition, it is suggested to reduce filter cake thickness and cake permeability to minimize this problem.

4. Mechanical sticking: Expected while drilling the salt zone.

Remedy

This type of problem can be avoided using salt saturated mud while drilling this formation.

5. Directional drilling: The max. inclination angle lies between 30, so we may face difficulty in hole cleaning, so cleaning is considered by low viscosity follow by high viscosity and the use of steerable system will be helpful to follow the direction and avoid severe dogleg in inclination and direction.

Remedy

The trajectory of the well should be carefully monitored in order to avoid risks of collision with existing wells of the same field especially in first 500-m.

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2.21 REFERENCES: 1. Farahat, M.S. Drilling Engineering 1. 2nd. Suez : Suez Canal University, Faculty of Petroleum and Mining Engineering. 2. Brantley, J. E.,. Rotary Drilling Handbook . s.l. : Pulmer Publishing, 1961. 3. Adams, N. J. A Complete Well Planning Approach. 2nd. Tulsa : PennWell Books, 1985. 4. Rabia, H. Oil well Drilling Engineering Principles and Practice. U. K. : Graham and Trotaman , 1985. 5. Bourgoyne, A. T. Applied Drilling Engineering. s.l. : SPE Text Book Series, 1991. 6. Gabolde, Gilles and Nguyen, Jean â&#x20AC;&#x201C;Paul. Drilling Data Handbook . s.l. : Editions Technip, 2006. 7. Nelson, E. B. Well Cementing. s.l. : Schlumberger Educational Services, 1990. 8. C., Gatlin. Drilling Engineeing. Texas : Petroleum engineering, Department of Petroleum engineering, University of Texas, 1960. 9. Droppert, V.5. Application of Smart Well Technology . s.l. : Delft University of Technology, December 2000. 10. Al-Mejed, M. E. Hossain & A. A. Fundamentals of Sustainable Drilling Engineering 2015.

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Reservoir

Reservoir Engineering is the branch of petroleum engineering that involves assessing oil and gas deposits. Reservoir engineers firstly estimate the size of a reservoir, and then determine how much oil and gas reserves are in the reservoir and finally work out how to maximize the economic return from extracting them

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The volume of hydrocarbons contained in a reservoir may be calculated either directly by volumetric methods, or indirectly by material balance. Accuracy of the volumetric method depends primarily on accuracy of data for porosity, net thickness, hydrocarbon saturation, and areal extent of the reservoir. Accuracy of the material balance method is primarily dependent on reliability of production data and PVT relationships for the reservoir hydrocarbons. Since produced water has no economic value, production records for water are frequently less reliable than for oil or gas. Casing leaks and poorly cemented casing are other possible sources of error in determining the volume of water produced from a reservoir. Accuracy of material balance calculations increases as more hydrocarbons are produced from the reservoir. Unfortunately, this means that the calculations are least reliable when accurate information on reservoir volume would be most useful: early in the life of the reservoir. Satisfactory accuracy from material balance calculations can usually be achieved after roughly five to ten percent of the hydrocarbons originally in place have been produced.

3.1.1. Volumetric analysis:

The volumetric method for estimating hydrocarbon volume is based on the use of geologic maps, usually derived from log and core data.

3.1.2. Material balance analysis:

The term “material balance” is well accepted in reservoir engineering that it can’t be changed, however the subject could more accurately be called “volumetric balance”. When a volume of oil is produced from a reservoir the space once occupied by this oil must be filled by something else. Applications of material balance: Material balance equation has been in general used for: 1) Determining the initial oil in place. 2) Calculating water influx. 3) Predicting reservoir pressure. General difficulties in applying material balance: 1) Lack of PVT data for specific reservoirs. 2) The assumption of constant liberated gas composition. 3) Accuracy of production data. 4) Accuracy of reservoir pressure data. Limitations of material balance: 1) Thicker formations of high permeabilities and low oil viscosities where the average reservoir pressures are easily obtained. 2)Producing formations composed of homogenous strata of nearly the same permeability. 3) In case of no very active water drives and no gas caps which are large compared with oil zone because of the very small pressure decline in case of very active water drive and large gas cap formations.

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3.2. Sources of reservoir energy and primary production: The overall performance of oil reservoirs is largely determined by the nature of the energy, i.e., driving mechanism, available for moving the oil to the wellbore. There are basically six driving mechanisms that provide the natural energy necessary for oil recovery.

3.2.1 Water drive:

A water drive reservoir has a hydraulic connection between the reservoir and a porous, water saturated rock called an aquifer.

he water in an aquifer is compressed. As reservoir pressure is reduced by oil production, the water expands, creating a natural water flood at the reservoir /aquifer boundary

3.2.2. Solution â&#x20AC;&#x201C;gas drive:

This type of reservoir the principle sources of energy is a result of gas liberation from the crude oil and the subsequent expansion of the solution gas as the reservoir pressure is reduced.

3.2.3. Rock and liquid expansion:

When an oil reservoir initially exists at a pressure higher than its bubble point pressure, the reservoir is called under saturated reservoir. As the reservoir pressure declines, the rock and fluids expand due to their individual compressibility so the expansion of the fluid and reduction in the pore volume, force the crude oil and water out of the pore space to the well bore. 202

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3.2.4. Gas cap drive:

When a reservoir has a large gas cap, there maybe a large amount of energy stored in the form of compressed gas, the gas cap expands as fluids are withdrawn from the reservoir displacing the oil by a gas drive assisted by gravity drainage.

3.2.5. Gravity Drainage: Gas bubbles that are evolved from solution as pressure declines near a producing well will migrate toward the well and be produced. Gas bubbles that are evolved at a greater distance from the well will migrate up dip displacing oil downward toward the well.

3.3. Gawaher Field Reservoirs Summary

The production from Meleiha Development Lease is mainly coming from Bahariya Formation which can be divided into several separate reservoirs numbered from I to VI. In this case study we are concerned only with Bahariya I, II and III and we are going to be more focused on Bahariya I and III as major producers while neglecting Bahariya II in most of the cases due to lack of sufficient data as well as being a minor producer. Since Bahariya reservoir fluids have almost the same physical and chemical characteristics in all Bahariya formations, the following data and any subsequent analysis of reservoir fluid properties will be considered valid and well representative of all reservoir fluids in all of them.

3.3.1. Reservoir Fluid Properties

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3.3.2. Reservoir Characteristics

3.4. Data Acquisition and Processing

The degree of accuracy of any output is chiefly dependent on the resolution and quality of provided data. So in the following section we are going to go through the methodologies followed for input data corrections and averaging to properly represent the reservoir in numerical equations.

3.4.1. PVT data adjustment

Several tests were conducted on a reservoir fluid sample at 174Â°F including differential vaporization test, flash vaporization test and separator test and the following results were obtained.

3.4.1.1. Flash Vaporization Test

A sample of the reservoir liquid is placed in a laboratory cell. Pressure is adjusted to a value equal to or greater than initial reservoir pressure. Temperature is set at reservoir temperature. Pressure is reduced by increasing the volume in increments.

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3.4.1.1.1. Test data

Applying Y_FUNCTION for correction results:

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3.4.1.1.2. RESULTS:

3.4.1.2. Differential Vaporization Test

The sample of reservoir liquid in the laboratory cell is brought to bubble-point pressure, and temperature is set at reservoir temperature. Pressure is reduced by increasing cell volume, and the cell is agitated to ensure equilibrium between the gas and liquid. Then, all the gas is expelled from the cell while pressure in the cell is held constant by reducing cell volume.

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3.4.1.2.1. results

3.4.1.3. Separator Test

A sample of reservoir liquid is placed in the laboratory cell and brought to reservoir temperature and bubble-point pressure. Then the liquid is expelled from the cell through two stages of separation. The vessel representing the stock tank is a stage of separation if it has lower pressure than the separator. Pressure in the cell is held constant at the bubble point by reducing cell volume as the liquid is expelled

3.4.1.4. PVT Data Adjustment 3.4.1.4.1. Oil Formation Volume Factor Adjustment

At pressures above bubble-point pressure, oil formation volume factors are calculated from a combination of flash vaporization data and separator test data.

The units involved in the calculations are

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At pressures below the bubble-point pressure, oil formation volume factors are calculated from a combination of differential vaporization data and separator test data

The units involved in the calculations are

3.4.1.4.2. Solution Gas-Oil Ratio Adjustment

Solution gas-oil ratio at pressures above bubble-point pressure is a constant equal to the solution gas-oil ratio at the bubble point.

Solution gas-oil ratios at pressures below bubble-point pressure are calculated from a combination of differential vaporization data and separator test data.

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3.4.1.4.3. Adjusted PVT Data

Oil Formation Volume Factor

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Solution Gas-Oil Ratio

Fluid Density

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Gas deviation factor

Gas gravity

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Oil viscosity

Gas viscosity

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3.4.2. Averaging Reservoir Rock Properties

Arithmetic averaging usually does not properly represent the average value of the reservoir property, so weighted averaging of the property can be the solution for better representation of reservoir property.

3.4.2.1. Averaging Reservoir Porosity

Weighted averaging of reservoir porosity can be calculated using the following equation.

3.4.2.2. Averaging Connate Water Saturation

Weighted averaging of reservoir connate water saturation can be calculated using the following equation.

3.4.2.3. Averaging Net/Gross Ratio

Weighted averaging of reservoir net/gross ratio can be calculated using the following equation.

3.4.2.4. Reservoir Average Petrophysical Properties 3.4.2.4.1. Bahariya I

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3.4.2.4.1. Bahariya III

3.4.2.5. Normalization and Averaging of relative permeability data

Results of relative permeability tests performed on several core samples of a reservoir rock often vary. Therefore, it is necessary to average the relative permeability data obtained on individual rock samples. Prior to usage for oil recovery prediction, the relative permeability curves should first be normalized to remove the effect of different initial water and critical oil saturations. The relative permeability can then be denormalized and assigned to different regions of the reservoir based on the existing critical fluid saturation for each reservoir region.

3.4.2.5.1. Normalization and averaging Procedure

Step 1: Calculate the normalized water saturation Sw* Step 2: Calculate the normalized relative permeability for the oil phase at different water saturation Step 3: Normalize the relative permeability of the water phase by applying the following expression Step 4: Determine the average normalized relative permeability values for oil and water as a function of the normalized water saturation by select arbitrary values of Sw* and calculate the average of kro* and krw* by applying the following relationships

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Step 5: The last step in this methodology involves denormalizing the average curve to reflect actual reservoir and conditions of Swc and Soc

3.4.2.5.2. Normalization of relative permeability data

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3.4.2.5.3.Averaging of normalized data and denormalization

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Denormalization

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3.4.2.6. averaging capillary pressure curves

Most effective approach is by applying Leverett J-Function : Capillary pressure data are obtained on small core samples that represent an extremely small part of the reservoir, and, therefore, it is necessary to combine all capillary data to classify a particular reservoir. The fact that the capillary pressure-saturation curves of nearly all naturally porous materials have many features in common has led to attempts to devise some general equation describing all such curves. Leverett (1941) approached the problem from the standpoint of dimensional analysis.

Where, J(Sw) = Leverett J-function, pc = capillary pressure, psi Ď&#x192;=interfacial tension, dynes/ cm ,k = permeability, md, Ď&#x2020;=fractional porosity .

3.4.2.6.1. Given

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3.4.2.6.2. Fitting an average curve for J_function :

3.4.2.6.3. RESULTS

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Normalized curve :

Each of these curves is for a plug of certain porosity and permeability. Thus, this method can be used to construct capillary pressure curve for any region in reservoir of known permeability. This makes that method of a major use in dynamic model, although many engineers may overlook using it and instead use an average capillary curve for reservoir.

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NORMALIZED CURVE

At average reservoir properties render:

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3.5. WATER PVT DATA: BEFORE PROCEEDING WITH ANY FURTHER CALCULATIONS, WATER FORMATION VOLUME FACTOR AND WATER COMPRESSIBILITY VS PRESSURE DATA SHOULD BE CALCULATED.

3.5.1. WATER FORMATION VOLUME FACTOR:

THE WATER FORMATION VOLUME FACTOR CAN BE CALCULATED BY THE FOLLOWING MATHEMATICAL EXPRESSION:

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3.5.2. WATER COMPRESSIBILITY: It is given by the following equation

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3.6.Bahariya I Material Balance Analysis :

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3.6.1. Determination of Reservoir Drive Mechanism:

From the analysis of the pressure performance of Bahariya I formation, it is obvious that reservoir pressure is greater than oil saturation pressure (bubble point pressure) of 810 psi until oct-2010 SO IT IS UNDERSATURATED RESERVOIR and then the reservoir pressure is greater than oil saturation pressure (bubble point pressure) of 810 psi SO IT becomes SATURATED RESERVOIR

3.6.1.1. Check if reservoir without water drive:

The material balance equation for an undersaturated reservoir without water drive can be written as Equation - MBE for undersaturated reservoir without water drive So we need to plot and see if it results a straight line passing through origin point then it is an undersaturated reservoir without water drive. 3.6.1.1.1.Check Procedure: Step 1: Get cumulative oil production (Np) and cumulative water production (Wp) at a specific date from production history.

Step 2: Get corresponding pressure at this date from pressure performance curve. Step 3: Get oil formation volume factor (Bo) and water formation volume factor (Bw) at this pressure from PVT data. Step 4: Get formation compressibility value at this pressure from special core analysis data. Step 5: Calculate oil compressibility at this pressure as follows Co=(Bo-Boi)/(Boi (Pi-P) ) Equation - Oil compressibility Step 6: Calculate total effective formation compressibility as follows

Step 7:Calculate values of F and Eo as follows

Step 8: Plot values and analyze the results 232

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From the graph, it is clear that this model of without water behaves as a straight line of R2 = 0.987 with a perfect match with production history. It also shows that OOIP (N) = 31.2355 MMSTB, which is more greater than that obtained using volumetric method (7.7 MMSTB). So this is probably the best model to describe the reservoir so far but we are going to check for the presence of an aquifer to confirm the results. 3.6.1.2. Check if reservoir with water drive: The material balance equation of an undersaturated reservoir with water drive can be written as follows

Equation - MBE for undersaturated reservoir with water drive

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3.6.1.2.1. Check for steady-state bottom water drive For steady-state bottom water drive, the mathematical expression of water encroachment is written as follows

Equation- Water influx in steady-state water drive So material balance equation will be expanded to

Equation - MBE for undersaturated reservoir with steady-state water drive 3.6.1.2.1.1. Check procedure step 1 Prepare Np, Wp, Bo, Bw, Co, Ce, Et, F as explained in the previous check procedure.

step 2 Calculate at each time step step 3

Calculate and plot

If reservoir exhibits a straight line, then it is steady-state water driven reservoir

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Reservoir

Water influx rate in semi-steady state water drive can be mathematically expressed as

3.6.1.2.2.1. Check procedure step 1 Get values of steady-state water constant (k) from previous test results step 2 Calculate the value of the reciprocal of steady-state constant (1/K) step 3 Calculate the values of ln(t) while noting that t is in days. step 4 Plot values of (1â &#x201E;K) Vs Ln(t)

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From the result graph (figure 37), it is clear that semi-steady state model does not generate a straight line. So our reservoir is NOT semi-steady state water driven. 3.6.1.2.3. Unsteady state water drive model checks: There are several models for describing unsteady state water drive reservoirs but we are going to assume bottom water drive and take Van Everdingen and Hurst (1949) analytical solution to dimensionless form of diffusivity equation

3.6.1.2.3.1. Model assumptions • Perfectly radial reservoir system • The producing well is in the center and producing at a constant production rate of Q • Uniform pressure Pi throughout the reservoir before production 3.6.1.2.3.2. Aquifer properties assumptions Van Everdingen and Hurst assumed that the aquifer is characterized by • Uniform thickness • Constant rock and water compressibility • Constant permeability • Uniform porosity

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So to calculate the TD constant in the equation the following aquifer properties are used

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3.6.1.2.3.3. Calculations of Qt The authors expressed their mathematical relationship for calculating the water influx in a form of a dimensionless parameter that is called dimensionless water influx Qt. They also expressed the dimensionless water influx as a function of the dimensionless time tD and dimensionless radius rD. So Qt can either be calculated using tables like the ones listed below or use the equation provided by Van Everdingen and Hurst. The later trend was adopted to ensure higher accuracy and dynamic modelling for different aquifer properties

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So the best model that describes the reservoir is expressed with the MBE for undersaturated reservoir without water drive mechanism ( depletion drive ) and OOIP = 31.2355 MMSTB

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3.6.1.2.3.5. Comments: 1. pressure time performance curve (No clear curve to use ) There is an attached excel file of multiple options to select data points to draw the curve (Final pressure performance ) We select case 2 like the data from company 2. OOIP from volumetric method = 7.7 MMSTB But using MBE = 31.2355 MMSTB 3. OOIP from the saturated period gives 3MMSTB We think the (P-T) curve controls this great difference 4. Bah-1 is LAMINATED strata with much shale (That is why MBE can not obtain accurate results) 5. OOIP from company is 14.15 MMSTB (still greater than volumetric method) 6. GoR from production data above Pb changes greatly ( increases & decreases) ?! It is supposed to be equal to Rs 7. The relation between Krg/Kro is directly proportional not inversely

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3.7. Prediction of future reservoir performance: After obtaining a reservoir model with a good match of production history and old pressure performance, we can use this model to predict the future performance of this reservoir. To predict reservoir performance, we can select one of two assumptions based on the current development plan of the field 1.Assuming cumulative oil produced based on production rate and predict the pressure. 2.Assuming the reservoir pressure based on pressure performance and predict cumulative oil produced We have developed dynamic excel model to be able to predict cumulative oil produced and the results is shown as follows

3.7.1. Assuming reservoir pressure In this model we assumed reservoir pressure at prediction date based on reservoir pressure performance then used material balance model to predict cumulative oil production assuming that water production changes with the same trend as past history. 3.7.1.1. Prediction Procedure

Step 1 Prepare Bo and Bw using interpolation from PVT data and Cf from SCAL. Step 2 calculate NpRp at the end of production date.

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3.7.1.1.1. December 2015 Following the decline of the pressure trend, pressure is assumed to be 622.97 psi at December-2015. Prediction results is as follows

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3.7.1.1.2. june 2016 Following the decline of the pressure trend, pressure is assumed to be 579 psi at june-2016. Prediction results is as follows

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3.7.1.1.3. December 2016 Following the decline of the pressure trend, pressure is assumed to be 523.76 psi at December-2016. Prediction results is as follows

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3.7.1.1.4. june 2017 Following the decline of the pressure trend, pressure is assumed to be 545.75 psi at December-2016. Prediction results is as follows

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3.7.1.1.5. December 2017 Following the decline of the pressure trend, pressure is assumed to be 368.45 psi at December-2016. Prediction results is as follows

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3.8. Decline Curve Analysis: Decline curve analysis (DCA) is a graphical procedure used for analyzing declining production rates and forecasting future performance of oil and gas wells. Oil and gas production rates decline as a function of time; loss of reservoir pressure, or changing relative volumes of the produced fluids, are usually the cause. Fitting a line through the performance history and assuming this same trend will continue in future forms the basis of DCA concept. It is important to note here that in absence of stabilized production trends the technique cannot be expected to give reliable results.

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3.8.1. Types of decline curves 1. Exponential 2. Hyperbolic 3. Harmonic

3.8.2. Decline Curve Analysis for Bahariya 1 Formation

Production history starts from augst 2007 where flow rate starts to increase gradually until it reaches a maximum value of 394 STB/day in August 2012 then starts to decline. We tried to fit production history with one of the decline curve models then used it for prediction with abandonment rate of 25 STB/day and here is the summary of the analysis.

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3.9. Reserve Estimation results: After calculating the Original Oil In-Place (OOIP) using different methods and identifying reservoir drive mechanism we can now estimate the reserves by using this simple equation

The recovery factor is a basic uncertainty here but it can be estimated either according to drive mechanism or by analogy to other similar reservoirs within the region. From volumetric analysis, it was found that OOIP has a total average value of 7.7 MMSTB in Bahariya formation. Also, Material Balance Analysis shows that reservoir is without water drive mechanism which can have a recovery factor of 25%.

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References: 1. Khattab, Hamed. Applied reservoir engineering. 2. Ahmed, Tarek H. Reservoir Engineering Handbook. 4th. s.l. : Gulf Professional Publishing, 2010. 3. William D. McCain, jr. The properties of petroleum fluids. 2nd. Texas, Oklahoma : Penwell Publishing Company, 1990.

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4.1. INTRODUCTION Formation evaluation is the process of using borehole measurements to evaluate the characteristics of subsurface formation. These measurements may be grouped into four categories: 1. Drilling Operation Logs 2.Core Analysis 3.Wireline Well Logs 4.Productivity Tests Well logging is a formation evaluation technique that is used to extract information necessary for exploration, drilling, production and reservoir management activities. Log is a graphic representation of the variations versus depth of other parameters. Wireline logs are measurements of physical parameter in the formations penetrated by borehole, they are run while drilling has been stopped i.e. after the drill string has been pulled out from the borehole.

4.1.1. TYPES OF WELL LOGGING:

There are three major types of well logs: 1. The Logs used by geologists and reservoir engineers to evaluate the characteristics of the formations and fluids and quantify them. 2 The Logs used by drillers that provide technical information. 3. The Logs used by production staff to study fluid and fluid flow phenomena

Logs can provide either direct measurements, or an indication of: •Porosity, both primary and secondary 4.1.2. Objectives of well logging: (fractures and vugs). • Determination the nature and amount • Permeability, K. of fluids contained in the rocks. • Water saturation , • Determination of accurate values of hy• Hydrocarbon type (oil, gas or condendrocarbons saturation. sate), • Determination of accurate values of • Lithology, water saturation. • Formation dip and structure, • Determination of the lithology of the • Sedimentary environment, reservoir rock. • Travel time of elastic waves in a formation • Determination of permeability index. (Rock Mechanical Properties). • Determination of porosity. • Identify potential reservoir rocks and cap rocks. • Analyze sediment deposition conditions. • Locate “WOC” & “GOC “. 274

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4.1.3. Logging evolution

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MCM - Modular Configuration Maxis

1. Parking of logging unit in front of cat walk. 2. Rig Up (fixing of the top & bottom sheaves). 3. Testing tools before lowering down into the hole. 4. Lowering the tool into the well at the desired depth . 5. Logging process. 6. Pulling out the tool to the surface. 7. Rig Down

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4.1.5. LOGGING TOOLS â&#x20AC;˘ 4.1.5.1. GAMMA RAY LOG

It is a lithology log, used primarily to distinguish shales from non-shales, estimating bed boundaries (bed thickness), and shale content.

â&#x20AC;˘ 4.1.5.2. POROSITY LOGS

a)Neutron logs Various concepts of bombarding the formation with energetic neutrons, a thermal neutrons, gamma rays, fast neutrons can be received depending on the log concept. It responds to the hydrogen index in the different fluids, it is therefore a valuable tool to distinguish oil, water and gas.

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Accelerator Porosity Sonde (APS)

• 4.1.5.2. POROSITY LOGS

b)Sonic log The sonic log measures the speed of sound waves in the formation. The log presents slowness, Δt, which is converted to sonic porosity, s, assuming lithology, fluid slowness, and the proper sonic porosity transformation. The most common, but not necessarily the most accurate, is the WYLIE time average (WTA):

• 4.1.5.2. POROSITY LOGS

DENSITY LOG The density log measures e, the electron density. This is converted to (bulk density) using the relation; It is assumed that a fresh water fills the zones = 1.00 g/cc). Borehole Compensated Sonic (BHC)

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Eccentric Density Tool

â&#x20AC;˘ 4.1.5.3. LATERO LOGS The focusing electrode tools include the laterolog and spherically focused logs (SFL ) .These devices are much superior to the ES devices for large Rt / Rm values(salt mud and/or highly resistive formations) and for large resistivity contrasts with adjacent beds (Rt / Rs or Rs / Rt) . They are much more much better resolution of thin beds to moderately thick beds. Focusing electrode systems are available with deep, medium, and shallow depths of investigation.

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4.2. QUANTITATIVE INTERPRETATION •4.2.1. Procedure • Ensure that the logs are “on depth” relative to each other by taking a “ marker “ which is an anomaly or a distinctive response that appear on all logs in the same depth ,so the logs are all “on depth”. • Take the readings from the attached logs (if there are any corrections, make them carefully). • Calculate porosity from sonic log and density log. • Calculate the shale correction for neutron and density log. • Calculate the hydrocarbon correction for neutron and density log. • Calculate the effective porosity • Calculate the formation factor • Calculate water saturation and oil saturation.

4.2.2. Calculations

4.2.2.1. Calculate the shale content • Calculation of shale index (Ish):From gamma ray log:

• γ = gamma ray response in the zone of interest • γ_(min ) =the average gamma ray response in the clean sand formation • γ_max = the average gamma ray response in the cleanest shale formation

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Calculation of Vshale (Vsh):-

1-For tertiary rocks, the Larionov equation is:

2-The Stieber equation is:

3-The Clavier et al equation is:

4-For older rocks, the Larionov equation is:

We will use the Larionov equation for the older rock. 5-From resistivity log: Where: Rt = is the reading from resistivity log Rtsh = is the resistivity opposite to the cleanest shale zone 6-From neutron porosity log:

Where: ØN = neutron porosity log reading at zone of interest ØNsh = neutron porosity log reading opposite to the cleanest shale zone 7-From crossplot: Where: ØN = neutron porosity log reading at zone of interest ØNsh = neutron porosity log reading opposite to the cleanest shale zone ØD = density porosity log reading at zone of interest ØDsh = density porosity log reading opposite to the cleanest shale zone *

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* Calculation of Minimum Vshale (Vshmin) is the smallest value of Vsh among Vsh 4.2.2.2. Corrections : 1.Correction for sandstone : Since the neutron porosity log measures the porosity in L.S. units, three porosity units are added to the apparent neutron porosity to obtain the corrected neutron porosity for sandstone. ØNc = ØN + 3 2.Correction for shale : a)For neutron porosity: Where: ØNc = corrected neutron porosity to shale ØN = apparent neutron porosity from log ØNsh = apparent neutron porosity opposite to the cleanest shale b)For density porosity: Where: ØDc = corrected density porosity to shale ØD = apparent density porosity from log ØDsh = apparent density porosity opposite to the cleanest shale 4.2.2.3. Correction for hydrocarbon effect : Light oil or gas will cause the formation density (ρb) to decrease by an amount of ∆ ρb & apparent porosity (ØD & ØN) to increase by an amount of ( ∆ØD & ∆ØN ) respectively .

Where: SOR = residual hydrocarbon saturation (from relative permeability curves =0.2) P = formation water salinity (335000ppm) Øeff = true formation porosity t

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Notes: 1.assume hydrocarbon density (ρh) to be 0.917gm/cc. 2.determine the values of ∆ØN & ∆ØD from the above mentioned equations . 3.add ∆ØN & ∆ØD to the porosity corrected to shale. 4.Vsh used is the Vshmin.

4.2.2.4. Determination of water resistivity (Rw) : 1. From bulk density vs resistivity plot 2 .From charts by using formation water salinity & reservoir temperature 3. From SP 4. From Rxo & Rt

Rw from charts @ reservoir temperature = 176of & water salinity = 335000ppm is = 0.015.

Calculation of water saturation :Sw% can be determined by the following equation:

Where : F = formation factor Rw = formation water resistivity Rt = true formation resistivity That equation is for clean sand But for shaly sand the equation becomes:

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4.2.2.5. Calculation of oil saturation : So% can be calculated from the following equation

Well N2

4.3.1. well logs

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4.3.2. QUALITATIVE INTERPRETATION

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4.3.3. Net Pay and Reservoir Pay, depending on cutoffs

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4.4. Quantitative interpretation: Used constants

Shale volume calculations • By Gamma ray (linear, clavier, Strieber, older rocks, young rocks) • Neutron density • Resistivity

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4.4.1. Shale volume calculations

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4.4.2. Porosity reading corrections

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4.4.3. Effective porosity and saturation

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4.4.4. RESULTS

4.4.5.Crossplots for zones BAH-I, BAH-II, BAH-III 4.4.5.1. ARG

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4.4.5.2. BH1

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4.4.6. PICKETT CROSS PLOT

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References: • “SCHLUMBERGER LOG INTERPRETATION”, vol.1, 2 (1972-1989) • Halender D.D. “Fundamental of formation evaluation”, Oil & gas consultants ,international inc. ,Tulsa. • E.R.Crain ,”the log analysis handbook” , vol. 1 , PennWell publishing co. ,Tulsa ,Oklahoma ,USA. • “Theory , measurement,and interpretation of well logs”,Zaki Bassiouni, SPE textbook series vol.4.

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5.1 Introduction:

uring a well test, the response of a reservoir to changing production (oR injection) conditions is monitored. Since the response is, to a greater or lesser degree, characteristic of the properties of the reservoir, it is possible in many cases to infer reservoir properties from the response. Well test interpretation is therefore an inverse problem in that model parameters are inferred by analyzing model response to a given input. In most cases of well testing, the reservoir response that is measured is the pressure response. Hence in many cases well test analysis is synonymous with pressure transient analysis. The pressure transient is due to changes in production or injection of fluids, hence we treat the flow rate transient as input and the pressure transient as output. In well test interpretation, we use a mathematical model to relate pressure response (output) to flow rate history (input). By specifying that the flow rate history input in the model be the same as that in the field, we can infer that the model parameters and the reservoir parameters are the same if the model pressure output is the same as the measured reservoir pressure output.

Clearly, there can be major difficulties involved in this process, since the model may act like the actual reservoir even though the physical assumptions are entirely invalid. This ambiguity is inherent in all inverse problems, including many others used in reservoir engineering (e.g., history matching in simulation, decline curve analysis, material balance). However, the dangers can be minimized by careful specification of the well test in such a way that the response is most characteristic of the reservoir parameters under investigation. Thus in most cases, the design and the interpretation of a well test is dependent on its objectives. 314

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The objectives of a well test usually fall into three major categories: â&#x20AC;˘ Reservoir Evaluation. To reach a decision as to how best produce a given reservoir.we need to know its deliverability, properities , and size.Thus we will attempt to determine the reservoir conductivity(kh), initial reservoir pressure, and the reservoir limits (or boundaries). â&#x20AC;˘ Reservoir management. During the life of a reservoir, we wish to monitor performance and well condition. It is useful to monitor changes in average reservoir pressure so that we can refine our forecasts of future reservoir performance. By monitoring the condition of the wells, it is possible to identify candidates for workover or stimulation. â&#x20AC;˘ Reservoir Description. the use of well test analysis for the purpose of reservoir description will be an aid to the forecasting of reservoir performance. In addition, characterization of the reservoir can be useful in developing the production plan.

5.2. Objectives of well Test Operations: Following important data & samples to be obtained from well test:

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5.3. Drill Stem Test(DST). A drill stem test is a test which uses a special tool mounted on the end of the drill string. It is a test commonly used to test a newly drilled well, since it can only be carried out while a rig is over the hole. In a DST, the well is opened to flow by a valve at the base of the test tool, and reservoir fluid flows up the drill string (which is usually empty to start with). A common test sequence is to produce, shut in, produce again and shut in again. Drill stem tests can be quite short, since the positive closure of the downhole valve avoids wellbore storage effects (described later). Analysis of the DST requires special techniques, since the flow rate is not constant as the fluid level rises in the drill string. Complications may also arise due to momentum and friction effects, and the fact that the well condition is affected by recent drilling and completion operations may influence the results. Normal drilling procedures control formation pressures and fluids through the use of a hydrostatic head. Drill Stem Testing brings these formation pressures and fluids to the surface, presenting a unique set of hazards since control is then maintained by mechanical and human systems. Guidelines to minimize the probability of failure of either system during a test should be planed and discussed before any test should get under way. Drill Stem Testing is a specialized area, however the responsibility for the success of the operation are well and truly defined between all parties involved. Operator, Contractor and Service Companies all have a major part to play. t

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5.3.1. Drill stem test function • To provide a bottomhole shut in ( Tester Valve ) . • To support and protect the gauge ( P, T ) . • To circulate and sample formation fluids . • To restore well equilibrium at the end of the test. Testing is done with two packers and will depend on condition at the time of the test and how many zones will be tested. It is not uncommon to have more than one zone to test and if in open hole will need some way of isolating the zones. The test is performed by setting packers and isolating a possible production zone. inflatable rubber packers are installed as part of the test assembly one will be set above and the other below the zone of interest, they can be made to temporarily seal off the annular region between the test string and the formation, this way we are able to isolate the zone of interest. If from the log there are more than one promising zone often a liner will be run and the complete open hole section will be isolated. Valve arrangements are inserted into the testing string some between the two packers, others above the top packer. The valves are initially in a closed position allowing the string to be run into the hole with a fluid cushion Such a cushion would have a draw-down “under-Balance normally 800 psi* inside the pipe. When the packers are set, the valve is opened and any fluids or gas contained in the formation is allowed to flow into the test string.

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The formation is then allowed to flow under control. up a test string, filling the string â&#x20AC;&#x153;it could be tubing or drill pipeâ&#x20AC;? with formation fluid. The fluid is then diverted and constantly checked. 318

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5.3.2. Types of Drill Stem Tests:

As with permanent completion components there are a variety of different drill stem test tools designed for a range of operating conditions and to perform different functionalities.

There are however two main categories of drill stem tests

5.3.2.1Open Hole Drill Stem Testing:

If hydrocarbons are detected in either cores oÂ r cuttings during drilling or indicated by the logs, an open hole DST provides a rapid, economical means to quickly assess the production potential of the formation. However, the technique requires the hole to be in very good condition and highly consolidated as the packer elements actually seal on the rock face. The open hole sections also limit the application of pressure on the annulus, therefore special strings are designed which are operated by pipe reciprocation and/or rotation. The multi flow Evaluator System (MFE) is a self contained open hole drill stem test string. If drilling is not halted to allow testing when pipe reciprocation and/or rotation. The multi flow Evaluator System (MFE) is a self contained open hole drill stem test string. If drilling is not halted to allow testing when a potential hydrocarbon bearing zone is encountered, an alternative test method is to wait until the well is drilled to total depth and then use straddle packers to isolate the zone of interest. The introduction of inflatable packers allows the effective isolation and testing of individual zones pinpointed using wireline logs. Open hole drill stem tests gather important early information, but reservoir testing requires more data over a longer period. The extent of reservoir investigated increases with test duration. A key factor governing the duration of an open hole test is wellbore stability. At some point the well may cave in on top of the packer and the string may get permanently stuck downhole, calling for an expensive sidetrack. These hazards of wellbore stability have been eliminated by testing after the casing has been set and in many sectors particularly offshore, cased hole testing has replaced traditional open hole drill stem testing. 319

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5.3.2.2 Cased Hole Drill Stem Testing:

As offshore drilling increased, floating rigs became common, increasing the potential for vessel heave to accidentally cycle traditional weight set tools and even un-set the packer. In addition, deeper more deviated wells make reciprocal tools more difficult to operate and control and thus jeopardize the safety of the operation. A pressure controlled system was designed specifically for these applications, eliminating the need for pipe manipulation after the packer has been set, and eventually becoming the new standard in drill stem test operations. The Pressure Controlled Test System (PCT) is a self-contained cased hole drill stem test string. The main test valve and other key tools are operated by specific signatures of annulus and/ or tubing pressure, which is why a thorough understanding of the different pressures and potential differentials is important in the design of the cased hole DST string. In the specific case of the PCT, the valve opens when pressure above a certain threshold - usually 1500 psi is applied on the annulus, and closes when this pressure is bled off. It uses the same annular pressure threshold regardless of depth, hydrostatic pressure and temperature (provided the design specifications of the tool are not exceeded). To do this, a chamber in the tool is precharged at the surface with nitrogen. A compensating piston ensures that the nitrogen acquires hydrostatic pressure as the tool is run in the hole. The pre-charge is ‘locked’ when the packer is set. Most pressure controlled systems provided today are termed fullbore which means that a minimum internal diameter of 21/4” is maintained throughout the string from top to bottom, which is essential for running wireline tools or coiled tubing inside the string to access the producing zone and hence enhance the flexibility of the test program. Services such as through tubing perforating, wireline or slickline conveyed sampling, pressure/temperature and production logging tools can readily be programmed into the test sequence either as main parts of the program or contingency measures. The flexibility of this type of system allows it to be run with most specialized system: • Permanent production packers or cement retainers. • TCP systems. • Surface Pressure Read Out Systems. The system is specifically useful in horizontal well applications, and offers almost unlimited testing, treating and stimulation operations in this technically demanding arena. 320

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DST pressure Records

Figure 2 DST Pressure Records

5.3.3. Conducting Drill Stem Test:

To determine the potential of a producing formation, the operator may order a drill stem test (DST). The DST crew makes up the test tool on the bottom of the drill stem, then lowers it to the bottom of the hole. Weight is applied to the tool to expand a hard rubber sealer called a packer. Opening the tool ports allows the formation pressure to be tested. This process enables workers to determine whether the well can be produced. Basically all it is, is a combination of valves That are made up on top of the test string and will divert the formation fluid to the choke and on to the separators. The surface test tree must be equipped with swab, master, kill and flow valves. A swivel, positioned above the master valve, must also be incorporated to allow rotation of the string. The test tree should be able to be hung off in a standard drill pipe elevator and must have connections for kill and flow lines facing down.

5.3.4. Test Choke:

Basically all the test choke is, is a combination of valves That are made up on top of the test string and will divert the formation fluid to the choke and on to the separators.

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5.3.5. Potential Hazards: • Being pinched or struck by the drill stem test tools during floor operations. • Swabbing the hole on the way out with the test tool could cause a kick to occur,which could result in a blowout leading to injuries and deaths. • A packer seat failure or fluid loss to an upper formation could cause a kick that might result in a blowout causing injuries and deaths. • Other hazards are similar to those encountered during tripping out /in.

5.3.6. Possible Solutions.

• Wear appropriate PPE. • Instruct workers in handling and using the special tools required during drill stem testing. • Keep a method for filling the hole in place at all times. Before any test starts, the rig management must ensure that the blow-out prevention system includes a kill system that is capable of pumping fluid into the well below the annular preventer and at least on-set of pipe rams. • Ensure all workers on the location understand the dangers before starting any drill stem test. They should be fully informed of and trained in appropriate safety procedures, including the use of safety equipment and breathing apparatus. If in an H2S area, post a sign indicating the test in full view for the general public to see. Post reliable people to stop them from coming to the location. Define a minimum of two muster points with all vehicles parked in an appointed area.

5.4 Types of Tests: 5.4.1 Drawdown Test

In a drawdown test, a well that is static, stable and shut-in is opened to flow. For the purposes of traditional analysis, the flow rate is supposed to be constant (Figure 1.2).

Figure 3 Drawdown Test

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Many of the traditional analysis techniques are derived using the drawdown test as a basis. However, in practice, a drawdown test may be rather difficult to achieve under the intended conditions. In particular: (a) it is difficult to make the well flow at constant rate, even after it has (more-or-less) stabilized, and (b) the well condition may not initially be either static or stable, especially ifit was recently drilled or had been flowed previously. On the other hand, drawdown testing is a good method of reservoir limit testing, since the time required to observe a boundary response is long, and operating fluctuations in flow rate become less significant over such long times.

5.4.2 Buildup Test:

In a buildup test, a well which is already flowing (ideally at constant rate) is shut in, and the downhole pressure measured as the pressure builds up (Fig. 1.3). Analysis of a buildup test often requires only slight modification of the techniques used to interpret constant rate drawdown test. The practical advantage of a buildup test is that the constant flow rate condition is more easily achieved (since the flow rate is zero).

Figure 4 Build up Test

â&#x20AC;˘Buildup tests also have disadvantages:

(a)It may be difficult to achieve the constant rate production prior to the shut in. In particular, it may be necessary to close the well briefly to run the pressure tool into the hole. (b)Production is lost while the well is shut in.

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5.4.3 Injection Test:

An injection test is conceptually identical to a drawdown test, except that flow is into the well rather than out of it. Injection rates can often be controlled more easily than production rates, however analysis of the test results can be complicated by multiphase effects unless the injected fluid is the same as the original reservoir fluid.

Figure 5 injection Test

5.4.4 Fall off Test:

A falloff test measures the pressure decline subsequent to the closure of an injection .It is conceptually identical to a buildup test. As with injection tests, falloff test, interpretation is more difficult if the injected fluid is different from the original reservoir fluid.

Figure 6 fall aff Test 324

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5.4.5 Interference Test:

In an interference test, one well is produced and pressure is observed in a different well (or wells). An interference test monitors pressure changes out in the reservoir, at a distance from the original producing well. Thus an interference test may be useful to characterize reservoir properties over a greater length scale than single-well tests. Pressure changes at a distance from the producer are very much smaller than in the producing well itself, so interference tests require sensitive pressure recorders and may take a long time to carry out. Interference tests can be used regardless of the type of pressure change induced at the active well (drawdown, buildup, injection or falloff).

5.5.Some important concepts in well test: 5.5.1 The Skin Effect:

Pressure transmission does not take place uniformly throughout the reservoir, since it is affected by local heterogeneities. For the most part, these do not affect the pressure change within the well, except those reservoir heterogeneities which are in the immediate vicinity ofthe wellbore. In particular, there is often a zone surrounding the well which is invaded by mud filtrate or cement during the drilling or completion ofthe well -- this zone may have a lower permeability than the reservoir at large, and thereby acts as a â&#x20AC;&#x153;skinâ&#x20AC;? around the wellbore, causing higher pressure drop.

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5.5.2 effective wellbore radius: This is the smaller radius that the well appears to have due to the reduction in flow caused by the skin effect.

5.5.3 Flow Efficiency:

A term sometimes used to describe the wellbore damage is flow efficiency. the ratio of the theoretical pressure drop if no skin had been present to the actual pressure drop measured during the test. The flow efficiency parameter can be used to calculate the flow rate that could be achieved if the wellbore damage were removed (by stimulation) since it is also the ratio of the ideal (zero skin) flow rate to the actual flow rate.

5.5.4 Wellbore Storage:

We have understood that, in most cases, well test analysis is the interpretation of the pressure response of the reservoir to a given change in the rate (from zero to a constant value for a drawdown test, or from a constant value to zero for a buildup test). However, for many well tests, the only means of controlling the flow rate is at the wellhead valve or flow line. Hence although the well may produce at constant rate at the wellhead, the flow transient within the wellbore itself may mean that the flow rate from the reservoir into the wellbore (the â&#x20AC;&#x153;sand faceâ&#x20AC;? flow rate, q,1 ) may not be constant at all. This effect is due to wellbore storage. Wellbore storage effect can be caused in several ways, but there are two common means. One is storage by fluid expansion, the other is storage by changing liquid level.

Figure 8 wellbore storage 326

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• For a fluid expansion storage coefficient,

• For a falling liquid level storage coefficient,

Figure 9 log- log plot between ∆p and ∆t

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5.6 Reservoir Boundary Response: 5.6.1Closed Boundaries:

When a reservoir (or a well’s own “drainage region”) is closed on all sides, the pressure transient will be transmitted outwards until it reaches all sides, after which the reservoir depletion will enter a state known as pseudosteady state. In this state, the pressure in the reservoir will decline at the same rate everywhere in the reservoir (or drainage region). Thus a pseudosteady state is not at all steady, and corresponds to the kind of pressure response that would be seen in a closed tank from which fluid was slowly being removed.

Figure 10 closed boundries

5.6.2 Fault Boundaries:

Fault boundaries usually act as impermeable barriers, and therefore the pressure response of a well close to a single linear fault can begin to look like the response of a closed reservoir. However, the response is actually different. Since the well responds to only one boundary instead of being completely closed in on all sides, there is no pseudosteady state (at least not initially). Due to the influence calculable by superposition (described later), the well “sees itself in the mirror”, and the net late time response is that of two identical wells. The semilog straight line of the original infinite acting response will therefore undergo a doubling in slope at the time the boundary effect is felt.

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5.6.3 Constant Pressure Boundaries:

When the reservoir pressure is supported by fluid encroachment (either due to natural influx from an aquifer or gas cap, or by fluid injection) then a constant pressure boundary may be present. Such a boundary may completely enclose the well (as, for example, for a production well surrounded by injectors) or may be an open boundary to one side of the well (for example, in the case of an isolated producer/injector well pair). The effect of any constant pressure boundary will ultimately cause the well pressure response to achieve steady state, at which the well pressure will be the same constant pressure as the boundary.

5.7 Estimation of average reservoir pressure â&#x20AC;˘ Middle Time Region Methods - Matthews-Brons-Hazebroek Method - Ramey-Cobb Method â&#x20AC;˘ Late Time Region Methods - Modified Muskat Method. - Arps-Smith Method.

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5.7.1 Middle Time Region Methods: •Based on extrapolation and correction of MTR pressure trend •Advantages: –Use only pressure data in the middle-time region • Disadvantages: – Need accurate fluid property estimates – Need to know drainage area shape, size, well location within drainage area – May be somewhat computationally involved

5.7.2 Late-Time Region Methods:

•Based on extrapolation of post-middle-time region pressure trend to infinite shut-in time •Advantages: – No need for accurate fluid property estimates. – No need to know drainage area shape, size, well location within drainage area. – Tend to be very simple. •Disadvantages: –Require post-middle-time-region pressure transient data.

5.8 Type Curve Analysis: • The type curves are used to properly analyze a test or to double-check the results obtained with conventional methods with those obtained with type curve matching. • Fundamentally, a type curve is a pre-plotted family of pressure drawdown curves generated by obtaining solutions to the flow equations with specified initial and boundary conditions. • Some of these solutions are analytical; others are based on finite-difference approximations generated by computer reservoir simulators.

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5.8.1 Objectives:

• Identify wellbore storage and middle time regions on type curve. • Identify pressure response for a well with high, zero, or negative skin. • Calculate equivalent time. • Calculate wellbore storage coefficient, permeability, and skin factor from type curve match.

Example of type curves:

• Gringarten Type Curve. • Pressure/Derivative Type Curve. • Diagnostic Plots

5.8.2 Gringarten Type Curve:

• Constant rate production • Vertical well • Infinite-acting homogeneous reservoir • Single-phase, slightly compressible liquid • Infinitesimal skin factor • Constant wellbore storage coefficient

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5.9 Some types for buildup curves:

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5.10 Analytical Method:

The given data for well(N-1X)

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Step 1

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Step 2

Plot ∆p vs ∆t on log-log scale. After plot ∆p vs ∆t on (log-log) scale , draw a unit slope straight line tangent to points ,then measure from(1 to 1.5 cycle) to get end of wellbore storage. In this problem the end of wellbore storage at ∆t=0.7 hrs Assume that (∆t/∆p)=((0.125)/(227.16))=0.00055

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Step 3 Plot pws vs ((∆t+tp)⁄(∆t)) on (semi -log) scale:

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Step (4)

m=Slope= 96.5*2.303= 222.2395 psi/cycle.

Step (5)

Step(6)

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Step 7

â&#x2C6;&#x2020;Ps=381.5972268 psi Step 8

Step 9

FE=79.8660244%

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Step 10

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Step(11)

Calculate the end of WBS (If exist) and When the boundary effect starts: From (log-log) plot measure From (1 to 1.5 cycle) to get the end of wellbore storage it will be at â&#x2C6;&#x2020;t=0.7 hour

Step(12)

It isnot reaching to boundary

Calculate average reservoir pressure by different methods:

Figure 11 MBH curves 341

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From the curve PMBH=0.03835 Calcaluate average Reservoir pressure

Pavg= 2312.32818 Psia

Figure 12 MDH curve 342

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Table2 shows Pavg results

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5.11 Saphir method : Step(1) Entered data(tp=13.71667 hrs, q=585 stb/day, tshutin=18.75 hrs, q at shutin=0) to loading Q. step(2) Entered data for (Pws and time) to load pressure. Step(3) Make an extract for (dp) to drawing(Log-log) plot and (semi-log) plot. Step(4) Make an extract for (dp) to drawing (log-log plot) and (semi-log) plot. Step(5) Make a model for our case study. Step(6) Make an improving for all charts. Note: The next pages from (Saphrir software) that show all results for our case.

Well model

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Saphir Results:

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5.12 Comparison between analytical Method and saphir Modeling:

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References:

1.Elsayed,said K. well test course .s.I. : Suez University, Faculty of Petroleum and Mining Engineering. 2.Salem,Adel. well test design and analysis. s.I. : Suez University, Faculty of Petroleum and Mining Engineering. 3. Roland N. Horne. “Modern well test analysis”. Stanford University,1990. 4. Amanat U. Chaudhry. “oil well testing Handbook ”. Houston, Texas,2004. 5.John lee. “well Testing”. Texas A&M University,1982.

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6.1 General Introduction

Once a well has been drilled to total depth (TD), evaluated, cased and cemented, engineers complete it by inserting equipment, designed to optimize production, into the hole. The driver behind every well comple¬tion state whether for a complex or basic well, is to recover, at a reasonable cost, as large a percentage of the original ail in place (00 IP) as possible. Completion, in petroleum production, is the process of making a well ready for production (or injection). This principally involves preparing the bottom of the hole to the required specifications, running in the production tubing and its associated down hole tools as well as perforating and stimulating as required. In order to analyze the performance of a conventionally completed flowing well, it is necessary to recognize that there are three distinctive phases, which have to be studied separately and then finally linked together before an overall picture of a flowing wells behavior can be obtained. These phases are: • The inflow performance (inside formation). • The vertical-lift performance (tubing performance). • The bean performance (through the choke).

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6.2 Inflow performance of oil wells :

The inflow performance relationship IPR (insides formation) for a well is the relationship between flow rate into the well bore and well bore flowing pressure Pwf.

6.2.1 For under saturated reservoirs

Where (Pwf>Pb) IPR can be calculated by assuming straight line relationship between Pwf&q (const productivity index),where

6.2.2 For saturated reservoirs

IPR will not be straight line, it will be curved. the correlation and work of Vogel is the most representative one. Although the method was proposed for saturated dissolved gas drive reservoirs, it was found to apply for any reservoir in which gas saturation increase as pressure decrease .Vogel original method didnâ&#x20AC;&#x2122;t account for the effects of non zero skin factor.

Also this method can be applied for under saturated reservoirs where (Pe<Pb), but here two test cases must be considered.

6.2.3Generalized Vogel inflow performance:

If the reservoir pressure is above bubble point and yet the flowing bottom hole pressure is below

Standing correlation is used to modify Vogelâ&#x20AC;&#x2122;s method to account for either damage or stimulation around the well bore.

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6.2.4 Current and predicted IPR 6.2.4.1 Vogel Method:

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6.4.2.2 Beggs Method:

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6.2.4.3 Fetkovich Method:

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6:3 Vertical lift performance

For vertical lift performance, multi flow correlations have a lot of empirical equations and dimensionless groups, which are rather difficult and complicated. Therefore, these correlations have been programmed on computer. The present study utilizes that is known as system analysis model program (SAM). This is a technique used to optimize oil and gas well performance by analyzing the complete producing system. Using Beggs and Brill correlation.

Tubing Size Selection

By using SAM program with Beggs and Brill correlation, we can calculate the vertical lift performance for various tubing sizes.

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SO The OPTIMUM TUBING SIZE IS 2.875 ‘’

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6.4 WELL COMPLETION

6.4.1 Introduction:

Certain equipment must be placed in the wellbore, and various other items and procedures must also be used to sustain or control the fluid flow. This equipment and any procedures or items necessary to install it are collectively referred to as a well completion.

6.4.2 Completion of naturally flowing wells 6.4.2.1 Reservoir completion methods

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6.4.2.2 Upper completion methods:

There are two main types of connections between the pay zone and the borehole: â&#x20AC;˘ open hole completion â&#x20AC;˘ cased hole completions

6.4.3 Open-hole

A well completion that has no casing or liner set across the reservoir formation, allowing the produced fluids to flow directly into the wellbore. This type of completion suffers the major disadvantage that the sandface is unsupported and may collapse. Also, without any casing or liner installed, selective treatments or remedial work within the reservoir section are more difficult. Open hole completions are used where there is only one zone which is either very well consolidated or provided with open-hole gravel packing for sand control. This is valid as long as there are theoretically at least no interface problems.

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6.4.4 Cased hole completion:

A completion configuration in which a production casing string is set across the reservoir interval and perforated to allow communication between the formation and wellbore. Since perforations can be placed very accurately in relation to the different levels and interfaces between fluids, this method gives better selectivity for levels and produced fluids. The only condition, however, is a good cement bond between the formation and the casing string. Cased hole completions are mainly used when there are interface problems and/or when there are several levels. As a result, they are not only much more common, they are the most.

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6.4.5 Main configurations of production strings: 1. Conventional completions: This is a system whereby one or more production strings (tubing) are used for safety and/or other reasons. The rest of the equipment is not determined (whether there is a production packer, etc.). The fundamental characteristic of the tubing is that it is located completely inside the casing and that it is not cemented, therefore easy to replace. A- Single zone completion : The well is equipped with a single tubing. There are two main types of single-zone completions, depending on whether the tubing has a production packer on its lower end. The packer provides a seal between the casing and the tubing, thereby isolating and protecting the casing. Single-zone completions with tubing and a production packer are (he most widely used because of: â&#x20AC;˘ The safety due to the packer (government regulations and company rules increasingly stipulate that a packer is to be used particularly offshore in conjunction with a -subsurÂŹface safety valve on the tubing). â&#x20AC;˘ Their relative simplicity in comparison with multiple or other types of completion, in terms of installation, maintenance and work over.

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B. Multiplezone completions:

In the past, the technique of producing several levels together through the same tubing was used. It required only a minimum amount of equipment. However, the subsequent reservoir and production problems that were experienced have caused this practice to become much less common.

C-Parallel dual string and tubing annulus completion:

Here several levels are produced in the same well at the same time but separately, i.e. through different strings of pipe. Double-zone completions are the most common, but there can be three, four and even more levels produced separately. However, this significantly complicates the equipment that needs to be run into the well and especially makes any workover operations much more complex. There are a large number of systems, but let us simply consider: â&#x20AC;˘ Parallel dual string completion with two tubing, one for each of the two levels and two packers to isolate the levels from one another and protect the annulus. â&#x20AC;˘ Tubing-annulus completion with one single tubing and one packer, which is located between the two levels that are to be produced, with one level produced through the tubÂŹing and the other through the tubing-casing annulus.

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Basically this type of completion allows the development of several levels with fewer wells, and is therefore faster. In contrast, maintenance and workover costs are higher. As such it is particularly advantageous offshore, it is also used to develop one or more marginal level(s) that would otherwise not warrant drilling a well. However, it should be borne in mind that the ideal completion is the simplest. It will entail the simplest operations in terms of installation, maintenance and workover. Tubing-annulus completions are very few and far between. Though they have good flow capability (large cross-sections are available for fluid flow). This system does not protect the casing, among other drawbacks. Parallel dual tubing string completions are therefore the typical textbook example of mul¬tiple-zone completion. More sophisticated completions require careful study in order to avoid: • Problems in operation and production due to frequent wireline jobs • Problems of safety and operation during workover.

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D-Alternative selective completions: Here the idea is to produce several levels in the same well separately but one after the other through the same tubing without having to resort to workover. Production alternates in fact and wireline techniques are used to change levels. This type of completion is especially suited to a situation where one of the two levels is a secondary objective (very rapid depletion, simple observation from time to time. etc.) which would not warrant drilling a well. Besides packers, this technology also requires extra downhole equipment such as: â&#x20AC;˘ A circulating device consisting of a sliding sleeve to open or obstruct communication ports between the inside of the tubing and the annulus â&#x20AC;˘ A landing nipple allowing a plug to be set in the well. Parallel tubing string and alternate selective completion systems can be combined. For example two parallel tunings, each equipped for two levels in an alternate selective man-ner, can produce four levels separately, provided that only two are produced at the same time.

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2 Tubingless completion : A tubingless completion uses no tubing, but production flows through a cemented pipe instead. This rather unusual type of completion, is mainly used in certain regions and only under specific conditions.

A - Single zone tubingless completion

Production flows directly through a casing, usually of large diameter. Wells that are big proÂŹducers of trouble-free fluids can be exploited in this way with minimum pressure losses and the lowest possible initial investment. This system is found particularly in the Middle East.

B - Multiple zone tubingless completion

Production flows directly through several casings whose diameters may be very different from one another depending on the production expected from each level. Several levels with mediocre production can be produced in this way with a minimum number of wells and downhole equipment, i.e. with a minimum initial investment. This is true provided there are no safety or production problems (artificial lift. Workover. etc.). This type of completion is mainly encountered in the United States.

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C-Uncemented Liner Completions:

Uncemented liners are used to overcome production problems associated with open hole completions and to extend their application to other types of formations. The formation is supported by a either a slotted liner, sand screen or is gravel packed Although they have some advantages over open hole, they still have the same selectivity and undesired fluid problems.

D-Slotted Liner

This type of completion entails a liner with flow slots machined throughout its length installed below the production casing. The slot widths can range between 0.254 - 1.016mm. A slotted liner is used where there is a risk of wellbore instability to maintain a bore through the formation which otherwise might collapse and plug off all production. It also helps in liquid lift due to the smaller flow area.

E- Wire Wrapped Screen

A plain wire wrapped screen is used either as a simple filter to strain out small amounts intermittently produced sand from a relatively stable formation or as a sand retention where high permeability, coarse sands would readily flow onto the screen forming zone.

F- External Gravel pack

An open hole gravel pack is used where the sands are too fine or abrasive for screen. The open hole is under-reamed to remove drilling damage and to create annulus for the filter sized gravel to pack against the formation wall. When installed, it is the most effective sand control measure for weak sandstones unconsolidated rocks, however carries more risk than a cased hole gravel pack.

G-Cased Hole Gravel Pack

Cased hole gravel pack completions are used to control sand production in perforated completions. Unlike the open hole gravel pack, the cased hole gravel is placed between the cased hole and the sand screen, ideally, with the gravel forced into the perforations holding the formation sand in place.

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6.4.6 The equipment of naturally flowing wells:

1) Choke: Constriction in the flow line useful in restricting flow and applying back pressure on the well. Types of Choke: Surface chokes: Used in high energy well producing oil and gas from high pressure formation. A)Flow â&#x20AC;&#x201C; Plug (Fixed): Athick â&#x20AC;&#x201C; walled removable steel nipples bored longitudinally to provide side of flow opening desired. B) Shaffer adjustable surface bean : Provide high degree of accuracy in pressure control by changing clearance between a niddle and its seat. 2. Subsurface (bottom) Choke (fixed) : Used in low energy wells , Producing low pressure as rapid expansion of gas will occur after fluid pass Chocke providing higher flow velocity in lower end of flow column. Design of chokes : Where, Q = Flow rate, STB/day P = THP, Psi R = Gas liquid ratio, SCF/STB a = 0.612 b = 1.62 c = 0.677 D = Choke size / 64 (in)

1) Plot relation between Q & P @ various Chocke sizes. 2) Put Pu = 2 Pd , where Pd is the press. When no choke used 3) Using Pu and corresponding value of Q , calculate D using the above equation.

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2) Christmass tree :

Assemblage of valves & fittings attached to control head in high pressure wells producing large volume of oil and gas.

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3) Packers :

a) Isolate the csg from corrosive fluids or high pressure. b) To stabilize and control flow. c) In conjunction with artificial lift system. d) To selectively produce multiple zones. e) Contain annulus killing fluid.

Types of Packers 1)Cement packers 2)Packer pore receptacle 3)Production Packers: a.Permanent Packers. b.Permanent – Retrievable Packers. c.Retrievable Packers: i. Weight set Packers. ii. Tension set Packers. iii. Mechanical set packers. iv. Hydraulic set Packers. v. Hydraulic expansion seal vi. Open hole inflatable Packers.

Design of Packer:

1) Determine type of Packer 2) Force balance :

∆F = Pwf (Ap – Ai) – Po ( Ap – Ao ) – W , Lb

Where: Ap = Cross section area of packer , in2 Ai = Internal cross section area of Tbg , in2 Ao = Outer cross section area of Tbg , in2 Po = Pressure of fluid in the annulus , psia W = Length of Tbg * nominal weight , Lb Pwf = Bottom hole flowing pressure , psia Determine Setting of packer according to value of ∆F & Type of packer.

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DATA GIVEN:

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4) Safety valves :

1) Pressure differential safety valves. 2) Pressure operated safety valves. 3) Wireline retrievable safety valves 4) Tubing retrievable safety valves.

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6.5 ARTIFICIAL LIFT METHODS

6.5.1 Introduction:

The volume of work done in the area of artificial lift well performance is large indeed. This is due to the fact that the artificial lift well performance is controlled by a large number of interrelated factors. These factors are such as reservoir type, fluid characteristics, well bore characteristics, surface and subsurface equipment and input power to drive the system. A lot of efforts have been culminated in much research and development work in different separate areas such as: inflow, vertical lift, surface and subsurface equipment efficiency and no major work done in the area of total well system analysis. Moreover, the area of wellhead performance is still virgin so that further studies should be achieved to obtain more accurate and better predictability solutions.

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6.5.2 Methods of Artificial Lift Systems:

The purpose of any artificial lift method is to create a tubing intake pressure so that the formation can produce the objective flow rate, and lift these fluids to the surface with a suitable well head pressure to overcome the separator pressure and back pressure due to well head fittings and flow line pressure losses. The pressure gradient starting from the bottom hole flowing pressure up to the well head pressure for the pumping system . It is required to have a flowing pressure difference between the bottom-hole and the well head. This pressure difference consists of the potential energy difference (hydrostatic pressure) and the frictional pressure drop. The former mentioned pressure difference depends on the reservoir depth and the latter depends on the well length. If the bottom-hole pressure is sufficient to lift the fluids up to the top, then the well is under “natural flow or natural lift”. Otherwise, artificial lift is required. A pump can supply mechanical lift. An alternative technique is to reduce the density of the fluid in the well and thus reduce the hydrostatic pressure. This is performed by the injection of lean gas in a designated spot along the well. This technique is known as “gas lift “. The selection and design of the artificial lift equipment will continue to be a significant event in the life of most oil wells. The resulting profitability will either be increased or diminished depending upon the appropriate choice of the artificial lift equipment, and the credibility of the designer will be enhanced or lowered accordingly. The designer should be aware that the system efficiency is becoming increasingly more important, since energy costs continue to rise. The production engineer designing an artificial lift scheme can choose among gas lift and the other types of pumping systems. The optimal system is ultimately based on the economic considerations, which requires a careful comparison among alternatives over the life of the well or the reservoir. However, there are constraints that may eliminate one or more possible lift methods, or simplify the design procedure. In offshore development, the space limitations of an offshore platform generally preclude the use of rod pumps, with their large surface beam-pumping units. Likewise, in certain environmentally sensitive areas, where minimizing surface facilities is important, rod pumps may not be feasible .

6.5.2.1 Gas lift:

Gas lift technology increases oil production rate by injection of compressed gas into the lower section of tubing through the casing–tubing annulus and an orifice installed in the tubing string. Upon entering the tubing, the compressed gas affects liquid flow in two ways: a) The energy of expansion propels (pushes) the oil to the surface and b) The gas aerates the oil so that the effective density of the fluid is less and, thus, easier to get to the surface. 386

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Key considerations 1. High productivity index (PI), high bottom-hole pressure wells 2. High PI, low bottom-hole pressure wells 3. Low PI, high bottom-hole pressure wells 4. Low PI, low bottom-hole pressure wells

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6.5.2.2 Pumping System:

6.5.2.2.1Sucker Rod Pump: The sucker rod system mechanically lifts formation fluids from the bottom to the surface of the well by the reciprocating action of a sub-surface pump derived from the surface by means of a beam unit with a string of rods (steel and/or fiberglass) extended down the hole. The surface and down-hole equipment for a rod-pumped well The Pitman and the walking beam translate the rotary motion of the crank to a reciprocating motion of the polished rod. The down-hole pump consists of a barrel with a ball-and -seat check valve at its bottom (the standing valve) and a plunger containing another ball-and-seat check valve (the traveling valve). When the plunger moves up, the standing valve opens, the traveling valve closes, and the barrel fills with fluid. On a down stroke, the traveling valve opens, the standing valve closes, and the fluid in the barrel is displaced into the tubing. The sucker rod system is normally applicable for low production rates. For high rate, using long stroke units, high pumping speed and large plungers should be used . These pumps consist of a cylinder and piston with an intake and discharge valve. Vertical reciprocation of the rod will displace well fluid into the tubing. These are utilized in low to moderate wells which deliver less titan 4,500 BPD.

Key considerations

• The annulus is open to gas flow. • A tubing anchor may be required to reduce rod and tubing wear/stress. • The pump diameter must be of sufficient size. • The rods must be properly sized.

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6.5.2.2.2Hydraulic Jet Pump :

Hydraulic pump lift is utilized in crooked holes, for heavy oils and variable production conditions that cause problems for conventional rod pumping. A typical jet pump system consists of four main parts including: nozzle, throat, diffuser, inlet chamber, and pump housing, A power fluid is accelerated through a nozzle and then mixed with the produced fluid in the throat of the pump. As the fluids mix, some of the momentum of the power fluid is transferred to the produced fluid; in the diffuser; some of the kinetic energy of the mixed stream is converted to static pressure. In a jet pump, the nozzle converts the high pressure of the power fluid at low pressure by changing its velocity. Well fluids are mixed in the pump throat and the diffuser generates the discharge pressure (which is high due to decrease in the fluid velocity) and the combined fluids are produced back through the annulus . Jet pumps enjoy the advantage of having no moving parts so that dirty or gassy fluids can be produced without the wear effect, which the wear that will result in positive-displacement pumps. They can also be used at any depth. However, drawbacks to jet pumps are their low efficiency (generally in the 20-30 % ranges) and the need for high suction pressure to prevent cavitation in the pump. Jet pump installations are designed using characteristic pump charts in a manner analogous to the design of centrifugal pumps. In addition, careful calculation of the pump depth needed for providing sufficient suction pressure for preventing cavitation is required in designing a jet pump for a well.

Key considerations

• The number of flow conduits (production and power). • Pressure losses in the power and return lines. • Whether produced liquid can return up the casing. • Lubricator access to pump-in let or piston units. • The large casing size required for turbine units. • The power fluid/ oil separation facilities required. • The higher initial costs. 389

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6.5.2.2.3 Hydraulic Piston Pump: Hydraulic Piston pimp is a positive-displacement pump. It consists of an engine with a reciprocating piston driven by a power fluid connected by a short shaft to a piston in the pump end,The pump acts much like a rod pump, except that hydraulic pumps are usually double acting, meaning that fluid is being displaced from the pump on both the up and the down strokes. The high-pressure power fluid is injected down a tubing string from the surface and is either returned to the surface through another string of tubing or is commingled with the produced fluid in the production string. Either water or oil may be used as the power fluid. Thus the production rate is easily changed by changing the power fluid injection rate. Gary4 introduced a detailed study about the pump equipment and design. The hydraulic piston system is used in producing from wells produce few barrels up to 8000 BPD by using power fluid (oil or water) to drive the pump at the bottom of the well. The down hole pump is a reciprocating pump similar in action to a sucker rod pump . The performance characteristics of the system make it unique adaptability to a wide range of charging well conditions where its rate can be varied from 10% to 100% of the pump displacement capacity. Quality of power fluid16 is very important for positive displacement pumps. Therefore, solid must be removed to increase the pump life because the down hole pump has moving parts.

6.5.2.2.4 Electric Submersible Pump (ESP):

An ESP is used for moving large liquid volumes of low gas/liquid ratio from reservoirs with temperatures below 250Â°F. An electrical submersible pump (ESP) is a multi-stage centrifugal pump. ESP is capable of producing very high volumes of fluid. It is able to handle some free gas in the pumped fluid. A typical ESP completion is shown in The pumping system is consists of a transformer and motor controller at the surface and a three phase electrical pump, a seal section, a rotary gas separator (for high gas/liquid ratio wells) and a multistage centrifugal pump plus additional components as required by the well. The motor is situated so that the produced fluids flow around the motor, providing the required cooling, either by setting the pump above the producing interval, or by equipping the pump with a shroud that directs the fluids past the motor before entering the pump intake.

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Centrifugal pumps do not displace a fixed amount of fluid, as do positive-displacement pumps, but rather create a relatively constant amount of pressure increase to the flow stream. The flow rate through the pump will thus vary, depending on the pack pressure held on the system. The pressure increase provided by a centrifugal pump is usually expressed as a pumping head. For calculating this pressure increase (p), it is necessary to have the number of stages and the required horsepower . The run life of the electrical submersible pumping system is different from field to field and from country to country. The average run life7 is a couple of months for some fields and reaches a couple of years for others. This depends on many factors such as handling sizing design and operation. Care of these factors can increase the average run life.

Key considerations

• The annulus is open to atmosphere for gas venting (but not offshore). • A special wellhead is required for cable sealing. • Some cable protection is needed. • Motor cooling must be adequate. • The tubing size must be adequate to handle large volumes with minimum back pressure on the pump.

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6.5.2.2.5 Progressive Cavity Pump:

The progressive cavity pump (PCP) is a positive displacement pump, using an eccentrically rotating single-helical rotor, turning inside a stator. The rotor is usually constructed of a high-strength steel rod, typically double-chrome plated. The stator is a resilient elastomer in a double-helical configuration molded inside a steel casing.

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6.5.3 Artificial Lift Selection:

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6.5.4 In This Project We Discuss Two Types of Artificial Lift Methods: • Electrical Submersible Pump • Sucker rod pump

6.5.4.1 ESP

An electrical submersible pump (ESP) is a multi-stage centrifugal pump. ESP is capable of producing very highvolumes of fluid. It is able to handle some free gas in the pumped fluid. A typical ESP completion consists of a transformer and motor controller at the surface and a three phase electrical pump, a seal section, a rotary gas separator (for high gas/liquid ratio wells) and a multistage centrifugal pump plus additional components as required by the well. The motor is situated so that the produced fluids flow around the motor, providing the required cooling, either by setting the pump above the producing interval, or by equipping the pump with a shroud that directs the fluids past the motor before entering the pump intake. The major types of ESP applications are: 1-High water-cut wells producing fresh water orbrine. 2. Wells with multi-phase flow (high GOR). 3. Wells producing highly viscous fluids. 4- mainly it’s used in offshore wells. 5- very effective at high depths. 397

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THE 9 STEP for ESP design Step 1 - Basic Data

Collect and analyze all the well data that will be used in the design.

Step 2 - Production Capacity

Determine the well productivity at the desired pump setting depth, or determine the pump setting depth at the desired production rate.

Step 3 - Gas Calculations

Calculate the fluid volumes, including gas, at the pump intake conditions.

Step 4 - Total Dynamic Head

Determine the pump discharge requirement.

Step 5 - Pump Type

For a given capacity and head select the pump type that will have the highest efficiency for the desired flow rate.

Step 6 - Optimum Size of Components

Select the optimum size of pump, motor, and seal section and check equipment limitations.

Step 7 - Electric Cable

Select the correct type and size of cable.

Step 8 - Accessory & Optional Equipment

Select the motor controller, transformer, tubing head and optional equipment.

Step 9 - The Variable Speed Pumping System

For additional operational flexibility, select the variable speed submersible pumping system.

Following is a list of data required:

1. Well Data

a. Casing or liner size and weight. b. Tubing size, type and thread (condition). c. Perforated or open hole interval. d. Pump setting depth (measured & vertical).

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2. Production Data

a. Wellhead tubing pressure b. Wellhead casing pressure c. Present production rate d. Producing fluid level and/or pump intake pressure e. Static fluid level and/or static bottom-hole pressure f. Datum point g. Bottom-hole temperature h. Desired production rate i. Gas-oil ratio j. Water cut

3. Well Fluid Conditions

a. Specific gravity of water b. Oil API or specific gravity c. Specific gravity of gas d. Bubble-point pressure of oil. e. Viscosity of oil f. PVT data a. Available primary voltage b. Frequency c. Power source capabilities a. Sand b. Deposition c. Corrosion d. Paraffin e. Emulsion f. Gas g. Temperature

4. Power Sources

5. Possible Problems

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ESP DESIGN

Basic Data 1.Well Data: Casing size ID = 7”in Tubing size = 2.875”in Pump intake (V-D) = 5600’ ft Pump intake (M-D) = 5600’ ft Top perf. = 5900’ ft 2-Production data: WHP = 200 psi Ps = 2000 psi Pwf = 1464 psi P.I = 0.336 pbd/psi WC = 10 % GOR = 82 m3/m3 ql = 26 m3/d = 163.5229 bpd Qo = 23 m3/d = 144.6549 bpd PB = 810 psi 3- Well flowing conditions:

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4 - Power source:-

Current frequency =

Production

Production Capacity Pwf = 1464 psi @ ql = 163.5229 bpd Composite specific gravity = 0.8535 PSI = 94.48339 psi PIP = 1369.517 psi Press drop/1ft = 0.369566 ft/psi = 2.71 Gas Calculations Rs = 565.6959 SCF/STB Bo = 1.415997 bbl/STB Bg = 2.032442 bbl/Mcf Z factor = 0.88 Tg = 67.76178 Mcf Sg = 83.25384 Mcf Fg = no Fg Vo = 208.3933 BOPD Vg = 0 BGPD Vw = 16.35229 BWPD Vt = 224.7456 BFPD Vg/Vt = 0 % BY Vol. TMPF = 55382.58 lbs/day Comp. Sp.Gr. = 0.703311 No gas separator required Total Dynamic Head Hd = 322.9783 ft Ft = 89.6 ft Pd = 770.64 ft TDH = 1183.218 ft Pump Type Selection

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Pump Type Selection

From Charts or Tables select : REDA PUMP GN 2000 (540 SERIES-2917 RPM-50 HZ) @ q = 163.5229 bpd HP/S = 0.55 hp Eff. = 57 % HEAD/S = 30 ft no.# of stages = 80 BHP = 4.865 hp Optimum Size of Components Gas Separator Seal Section Same series as pump Motor SERIES ODâ&#x20AC;? HP VOLT AMP 540 5.43 100 1833 32 Electric Cable Select Cable #4 CU-#2 AL Voltage drop/1000 ft = 21.618 Cable Length = 5700 ft Flat Cable - Motor Lead Extension Pump Length = 14.8 ft SealLength = 6.3 ft Flat Cable Length = 27.1 ft Accessories Motor Controller SV = 446.7 V AMP = 12.9 KVA = 9.96

SELECT :

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6.5.4.1.2 Using PROSPER:

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6.5.4.2 SUCKER ROD PUMP DESIGN: WC = counter balance weight Sp = stroke length, in. Wf = weight of fluid, Lb/ft Wr = weight of rod in air, Lb/ft PRRL = Peak polished rod load, Lb MPRL = Max. polished rod load, Lb Ft1 = Max. Upstroke torque factor Ft2 = Max. Downstroke torque factor Atop = Cross sec.Area of top sec. of rods Bs = Buoyancy factor PT = Peak torque Er = elastic const., in/Ib.ft Fc = frequency factor Fo = differential load on the full plunger area, Lbs Ar = average rod cross sec. area

DESIGN STEPS

1. Known or assumed data: a. Pump displacement Q,bpd b. Max rod stress, psi c. Fluid level Df , ft d. pumping speed N, spm e. Plunger diameter DP, in f. Pump depth L, ft g. Length of stroke S, in h. Fluid specific gravity Gf i. Tubing size, in j. Sucker rod size (from table)

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2. Record the following factors( from tables) 1)Wr 2)Er 3)Fc 4)Et

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3. Calculate the non dimensional variables: a. Fo =.34 Gf Dp2 Df b. Fo/SKr =Fo /(S/ErL) C. N/No = (NL+245000)/Fc d. 1/Kt =Et L

4. Solve for Sp and PD:

Sp/S= (from table) PD=0.1166 Sp N Dp2 bpd IF the calculated PD is unsatisfactory, change assumed data and repeat steps 1 through 4.

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5. Determine non dimensional parameters: a. W=Wr*L b. Wrf=W(1-.127Gf) c. Wrf/Skr=

6. Record non dimensional parameters: a. F1= (F1/Skr)*Skr (from table) b. F2= (F2/Skr)*Skr (from table) c. T= (2T/S2kr)*Skr*S/2 d. Ta= (from table)

7. Operating characteristics of pump: a. PPRL= Wrf+F1*SKr b. MPRL=Wrf+F2*SKr c. PT=T*SKr*S/2*Ta d. Wc=1.06(Wrf+0.5 Fo) e. Rod stress=PPRL/Ar f. BHP=0.24332*PD*Gf*L/33000

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Data Given:

Qgross = 164 BPD W.C = 10.0% API = 38.0 GOR = 450 Scf/STB Bo = 1.41 Ps = 2350 psi

DESIGN STEPS:

GRAVITY OF OIL Go =141.5/ (131.5+API) =141.5/ (131.5+38) = 0.835

Determination of Composite Specific Gravity: TMPF =((Bopd*Go+Bwpd*Gw)*62.4*5.615) +(GOR*BopD*Gg*0.0752) BwpD = gross rate*(W.C)=300*0.1=30 bbl/day BopD = gross rate-(BwpD)=270 bbl/day TMPF = (270*0.835+30*1.12)*62.4*5.615) + (450*270*1.272*0.0752) TMPF= 102386.9124 Ib/day Comp SP.Gr =102386.9124/ (300*5.615*62.4) = 0.974

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Determination of Depth to Fluid Level

Pwf = Ps-(q/j) = 2030-(164/0.336)=1541.9 Psi Length of Fluid Column= 1700/ (0.433*0.974) =4030.9 ft Depth to Fluid Level (D) = 5848.5-4030.9= 1817.5996 ft

1- Assume Volumetric Efficiency = 90% V= (Q/Ev) = (300/0.9) = 333.33 bbl/day 2- (L=5600 ft). From Figure 5.6(WELL DESIGN BOOK) It indicate Use of an API Size (320) unit with (84- in) stroke. An Example of Unit Would Meet These Specifications is the (LUFKIN E-320D-84-30). This Unit Has Abeam load Capacity of (30000)Ib and maximum counterbalance effect(At the 64-in stroke) of 21645 ib 3- From Table(5-11) THE PLUNGER SIZE IS (1 1/2”), THE TUBING SIZE IS(2 1/2 “) AND ROD SIZES IS(3/4 , 7/8 )AND(1 IN). AND THE PUMPING SPEED IS(18) spm (BY INTERPOLATION). FROM TABLE (5.1) 3/4 A1= 0.442 in2 ,M1= 1.63 Ib/ft. 7/8 A2= 0.601 in2 ,M2 = 2.16 Ib/ft. 1 A3=0.785 in2 M3=2.88 Ib/ft. FROM TABLE (5.2)

Ap = 1.767 in2 PUMP CONSTANT= 0.262 bbl/day/in/spm.

FROM TABLE (5.3): At = 1.812 in2 4- FOR a(-3/4-7/8-1)(COMBINATION),(TABLE 5.4): R1=0.664-(0.0894*Ap) =0.506 R2=0.181+ (0.0478*Ap) =0.265 R3=0.155+ (0.0416*Ap) =0.229 5-

L1= (L*R1)=5600*0.506=2553.6 ft =2833.6 ft L2= (L*R2) =5600*0.265=1618.4 ft =1484 ft L3= (L*R3) =5600*0.229=1282.4 ft

6 - Acceleration factor (α) = (SN2)/70500= (144*18^2)/70500=0.662 417

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7- Assume That (E=30*10^6)

Effective Plunger Stroke(Sp) Sp=S+ ((40.8L2α)/E)-5.2GDAp/E(L/At+L1/A1+L2/A2+L3/A3) Sp =144+ ((40.8*5600^2*0.662)/(30*10^6))- ((5.2*0.974*5600*1.767)/(30*10^6))*(56 00/1.812+2834/0.442+1484/0.601+1282/0.785)= 149.51”

8- Q =KSpNEv

=0.262*149.51*18*0.9=634.57 bbl/day. THE DESIRED PRODUCTION RATE OF(300)BBL/DAY CAN BE OBTAINEd

9- Wr = (M1L1+M2L2+M3L3) 1.63*2834+2.16*1484+2.88*1282=11517.02 Ibs 10- Wf=0.433G (LAp-0.294Wr) =0.433*0.974(5600*1.767-0.294*11517.02) =2745.2 Ibs. 11-

12-

13-

14-

Wmax=Wf+Wr (1+α) =2745.2+11517.02(1+0.662) =21886.49 Ibs. THE BEAM LOAD IS WITHIN THE ALLOWABLE LIMIT OF (30000 Ibs) THE Max Rod Stress Is (Wmax/A3) = (21886.49/0.785) =27880.88 psi which is within the allowable limit of (30000psi). Ci = 0.5Wf+Wr (1-0.127G) = 0.5*2745.2+11517.02(1-0.127*0.974)=11464.99 Ibs. THE IDEAL COUNTERBALANCE EFFECT CAN BE OBTAINED SINCE AMAXIMUM EFFECT OF(21887 Ib) IS AVAILABLE. PEAK TORQUE PT= (Wmax-Ci)*S/2 =(21886.49-11464.99)*(144/2) =750348 In-Ib. An API size (320) Unit Has Arating of(900000 in-ib) And So The Peak Torque Is within allowable limits

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POWER REQUIREMENT OF THE PRIMEMOVER 15-

Assume the casing to be at atmospheric pressure. Net Lift of the Well LN= D+ (2.31 Pt /G) =5600+ (2.31*120/0.974)=5884.6 ft.

Hydraulic Horsepower:

Friction Horsepower:

Hh = 7.36*10-6 qGLN (7.36*10-6*300*0.974*5884.6)= 12.66 hp. =

Hf =6.31*10-7WrSN = (6.31*10-7*11517.02*144*18) =18.84 hp.

Brake horsepower: Hb =1.5(Hh+Hf) =1.5(12.66+18.84) =47.25 hp.

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6.6 Field Processing: 6.6.1 OIL AND GAS SEPARATION 6.6.1.1 Separator Components:

1. Primary separation section: For separating the bulk of the liquid from the well stream, it is desirable to remove quickly liquid slugs and large droplets of liquid from the gas stream in order to minimize turbulence and separate of liquid particles. This is accomplished by the use of tangential inlet, which circulate the fluid. 2.Liquid accumulation section : This section should be of efficient volume to handle fluid surges that may occur. The separation liquid should not disturbed by the flowing gas stream. 3. Secondary separation section: Is for removing the smaller liquid droplets. The major principle of separation in this section is gravity settling form the gas stream, thus minimization turbulence, it is important to decrease gas velocity. 4. Mist extraction section: Impingement is the most widely used principle for collection of small particles in liquid-gas separation. Particles strike a collecting surface. Two general types of mist extractor differ in intensity of centrifugal force. When a gas stream approaches an obstruction it veers around it, but the liquid droplets having a greater mass density, offer more resistance to change in direction and tend to continue in a straight line. Thus the larger particles collide (impingement) with confining wall and separated from the gas.

6.6.1.2 Types of Mist Extractors:

1) Van type mist extractor Consist of parallel metal plates with liquid collection pockets. The coalescence of small particles into droplets larger enough to settle by gravity aided by the centrifugal force and the collection surface. 2) Knitted-wire mesh pad

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6.6.1.3 Types of separator: 1. Vertical Separator: The well stream enters the separator through the tangential inlet, which imparts a circular motion to the fluids. A Centrifugal and gravity force provides efficient primary separation. A conical baffle separates the liquid accumulation system from primary section to ensure a quiet liquid. Surface releasing solution gas. The separated gas travels up ward through the secondary separation section where the heavier entrained liquid particles settle out. The gas flows through the mist extractor and particles accumulate until sufficient weight to fall into the liquid accumulation section. Sediments enter the separator and accumulate in the bottom and flushed out through the drain connection.

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2. Horizontal separator: -Single tube: the well stream enters through the inlet and strikes an angle baffle or dished deflector and strikes the side of the separator, producing maximum primary separation. Horizontal divider plates separate the liquid accumulation and gas separation section to ensure quick removal of solution gas. The separated gas passes through the mist extractor where liquid particles where liquid particles 10 micron and larger size are removed. -Double tube: consist of an upper separator section and lower liquid chamber. The mixed stream of oil and gas enters the upper tube. Liquid fall through the first connecting pipe into the liquid reservoir and wet gas flows through the upper tube where the entrained liquid separate owing to difference in density and to scrubbing action of mist extractor

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3. Spherical separator: The incoming well stream is split by the inlet flow diverter and directed tangentially against the wall of the separator. The liquid streams come together after flowing 180o around the vessel wall and then fall into the accumulation section to remain there until released. The gas stream is travelling through the large diameter and loses particles due to its reduced velocity. Then, the gas passes through mist extractor.

Factors affecting separation

• Operating pressure: a change in pressure effects changes in the gas and liquid densities, velocity and flowing volume. The net effect on an increase in pressure is an increased gas capacity of the separator. • Temperature, it affects the actual flowing volume and densities of the gas and liquid. The net effect of an increase of temperature is a decrease in capacity. • Well stream crude oil composition

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Stage separation

Stage separation is a process in which gasesous and liquid hydrocarbons are separated into vapor and liquid phases by two or more equilibrim flashes at consecutively lower pressure. As shown in figure two stage separation involves one separator and one storage tank. Three-stage separation requires two separators and a storage tank. Four-stage separation would require three separators and a storage tank. The tank is always counted as the final stage of vapor liquid separation because the final equilibrum flash occurs in the tank.the propose of of stage separation is to reduce the pressure on the reservoir liquids gradually, in steps or stages, so that a more stable stock tank liquid will result.

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6.6.1.4 DESIGN OF STAGE SEPARATION:

The equilibrium constant (k) values for each component at any pressure and temperature can be written as follows:

Ki= 1/P*(10)(a+cFi)

Where : P: The operating pressure ,psia A = 1.2 + 0.00045*P + 15*10-8* P2 C = 0.89 - 0.000017*P - 3.5*10-8*P2 Fi = bi*(1/Tbi-1/T) bi = Log(pci/14.7)/(1/Tbi-1/T) Tbi = normal boiling point temperature for C7+

for CO2

n = 7.3 + 0.0075*(T - 460) + 0.0016*P bc7+ = 1013 + 324*n - 4.256*n2 Tbc7+ = 301 + 59.85*n - 0.971*n2 +

Where : KCO2 = equilibrium ratio of CO2 KC1= equilibrium ratio of methane KC2= equilibrium ratio of ethane The API gravity for the separated oil can be calculated from the following equation : API = 6084 / AMWt + 5.9 Go = 141.5 / (131.5 + API)

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DATA GIVEN:

RESULTS: 1) T = 100 F

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RESULTS: 1) T = 200 F

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RESULTS: 1) T = 60 F

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CONCLESION :

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SO The Optimum Condition of Separator are P=60 Psig & T=60 F

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6.6.1.5 Separator Calculations:

As explained by Ref 1 (Tarek Ahmed) to select the optimum separator conditions (e.g. Pressure and Temperature ) that result into the highest API gravity and lowest formation volume factor and total gas-oil ratio .

6.6.1.6 Separator Design Using Graphical Method : Given Data: Operating Pressure = 60 psia Gas Flow Rate = .25 MMSCFD Oil Flow Rate = 560 BOPD

Procedure: 1- From Figure 1A ; Sivalls Charts @ P=100 Psia &G=.25 MMSCFD

So; We Select Separator 24’’×5’

2-Check For Oil Capacity. From table 1B,For gas-oil water separation; Settling volume V =1.1 BBL Separator Can handle Qr =1440*V/t =1584 BPD Oil needed to be handled Q =560 BPD

Qr is greater than Q .So, Separator is safe to be used.

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6.6.1.7 Heater Treater:

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6.6.1.8 Design of Heater Treater:

q t=560 STB/day q o= 515 STB/day q w= 45 STB/day γ o= 0.835 γ w= 1.02 Emulsion = 0.2% of produced water Tflowing=90oF Pflowing=20 psig Ttreating=150oF Specific heat of oil=0.5BTU/lb./oF Specific heat of water= 1 BTU/lb./oF Settling time=2.5 hr. Heating time =1 hr. Hay section=2ft Spread=1ft Heater treater diameter =6ft

1- Weight of Oil

2- Heat Load for Oil:

3- Weight of Water:

4- Heat Load for water

5- Total Heat Load

W = 62.4 × ϒo × qo × (5.615/24) = 62.4 × 0.835 × 515 × (5.615/24) ` = 6277.934 lb. /hr. Qo = W × Cp × T = 6277.934 × 0.5 × (150-90) = 188338.05 BTU/hr. W= 62.4 × ϒw × qw × (5.615/24) = 62.4 × 1.02 x 45 × (5.615/24) = 670.094 lb. / hr. Qw = W × Cp × T = 670.094 × 1 × (150-90) = 40205.646 BTU/hr. Q = Qw + Qo = 40205.646 +188338.05 = 228544.146 BTU/hr.

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6- Introduce 25% as a heat losses from treater. Q = 1.25 × 228544.146 = 285680.183 BTU/hr. Fire boxes are 200000; 250000; 300000; 600000 BTU/hr. So we select 300000 Btu/hr. 8- Heat transfer From Firebox to water bath It is taken as 10000 BTU/hr./Ft2 Heat transfer area=300000/10000 =30 Ft2 9- Calculation of lengths of sections. 1-Settling Section Assume; Settling time=2.5 hr.

Diameter =6 ft. Qemulsion = (515+0.2*45)*5.615/24=122.59 ft3/hr. Vemulsion = 122.59*2.5=306.49ft3 H=306.49/ (0.25*π*6^2) =10.84~11ft 2-Length of hay section h =2 ft. 3-Heating section Design to heat for 1 hr. h = 122.59* 1 / (0.25*π*6^2) = 4.34~5ft 4- Distance from spreader plate to fire tubes h =1ft 5-Free water Section V = 0.8*515*5.615*5/ (24*60) + (560+0.2*515)*5.615*1/ (24*60) = 9.388 ft3 H = 9.388/ (0.25*π*6^2) = 0.33~1ft 6-Gas separation section

Retention time=1 min Total flow rate = 560 STB/day V = 560*5.615*1/ (24*60) = 2.18 ft3 h = 2.18/ (0.25*π*6^2) = 0.07723~1ft

The Total length of heater treater = ∑h= 21 ft. The Diameter of heater treater = 6 ft. Total amount of heat required = 300000 BTU/hr.

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References:

•T.E.W Nind “Principles of Oil Well Production”, McGraw-Hill Book Company. New York 1964. •Arnoldk and Stewartm “Surface Production Operations” volume 1. •Prof. Dr. Ahmad A.M. El.Gibaly “Production Engineering Tools” Faculty of Petroleum and Mining Engineering, Suez Canal University. •Prof. Mohammed Mustafa “ Petroleum Engineering Course on Artificial lift Methods” Faculty of Petroleum and Mining Engineering, Suez Canal University •H.Dale Beggs “Production Optimization Using NODAL Analysis”, OGCI Publications Oil & Gas Consultants International Inc. Tulsa. •Boyun Guo, William C.Lyons and Ali Ghalambor “Petroleum Production Engineering A Computer-Assisted Approach”

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