Since the last issue, there had been changes in YoungPetro. Our former Editor-in-Chief, Natalia Krygier, entrusted me to take over the helm after her. Th e whole Editorial Team would like to thank you, Natalia, for your great contribution to the YoungPetro Magazine. Th e work you did during these years had a great impact on what YoungPetro is now. Karolina Zahuta and Maksymilian Łękowski are not a part of Editorial Team anymore. Th ank you all for your work and good luck on your further way. Fortunately, we have now new joiners which you will get along with soon. End of the year is always a great opportunity to sum things up and take a look back what has been achieved. Th e remaining year was full of conferences, meeting interesting people and gaining experience. It goes without saying, ATCE was the event that contained all of that and we were there. „On Stream” brings news from the industry and “How it works” is packed with the latest technology. Next, we will visit South Sudan with the paper that was presented at UPES SPE Fest 2017. Th en you will learn about Foam Enhanced Oil Recovery and Drilling in Natural Gas Hydrate Reservoirs. Going more forth, we can deep dive into CBM in India and analysis on Material Balance in Low Permeability Gas Reservoir. At the end, we will meet future with considerations on Artif i cial Intelligence in Oil and Gas Industry. Taking advantage of the opportunity, I would like to wish you all Happy New Year. Let 2018 be even more fruitful and packed with amazing events. Enjoy!
Editor-in-Chief
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Editor-in-Chief Patryk Bijak p.bijak@youngpetro.org
Marketing Filip Czerniawski Patryk Bijak
Deputy Editor-in-Chief Filip Czerniawski f.czerniawski@youngpetro.org
Ambassadors Josiah Wong Siew Kai - Malaysia Alexander Scherff – Germany Viorica Sîrghii - Romania Athansios Pitatzis – Greece Sagar Karla- India Alex Zakrzewski- UK Muhammad Bilal Akram- Pakistan Serhii Kryvenko- Ukraine/ Texas, USA Alahdal A. Hussein- Malaysia Ivan Bošnjak- Croatia
Art Director Alicja Pietrzyk alicjaa.pietrzyk@gmail.com Editors Wojciech Kurowski Maciej Górczak Wojciech Panek Milan Zięba Anna Orchel Karolina Potasiak Natalia Krygier
Publisher Fundacja Wiertnictwo - Nafta - Gaz, Nauka i Tradycje Al. Adama Mickiewicza 30/A4 30 - 059 Kraków, Poland www.nafta.agh.edu.pl
Graphic designer Patrycja Lanc Proof-reader Adam Sikorski
ISSN
2300-1259
Published by
An Official Publication of
The Society of Petroleum Eng ineers Student Chapter P o l a n d www.spe.net.pl
3
On Stream – Latest News
4
MIlan Zięba
Comparative Analysis of Static and Flowing Material
5
Balance on a Low Permeability Gas Reservoirs Sabooh Hasnain, Saad Ahmad, Mohsin Tariq Khan
Annual Technical Conference and Exhibition in San Antonio 2017
12
Application of Chemostragraphy to Petroleum Exploration & Field
15
Appraisal in South Sudan: An Example from from Melut Basin -
Kon Aguek Deng
Fly Ash Nanoparticles Enhance Foam Stability
22
Performance in SDS-Stabilized Foam Josiah Wong Siew Kai, Dr. Wan Rosli Wan Sulaim
Drilling In Natural Gas Hydrate Reservoirs
30
Shubham Satyam
Scenario of CBM in India and Enhanced CBM recovery
42
via C02-N2 Sequestration Patel Karan, Sachin Nambiar, Nahid Shaikh
How it Works? Agitator™ – NOV solutions
48
4
!
On Stream – Latest News
On Stream – Latest News Milan Zięba
The Libra Oilfield Starts Production At the end of November 2017 the exploitation of the huge Brazil’s oilfield has started. The operator of the Libra project is domestic Petrobras with 40% stake. The minority interests in the Libra field have got Shell, Total, CNOOC and CNPC. The reservoir is located about 230 kilometers off the coast of Rio de Janeiro and its recoverable oil reserves are estimated at 7,9 billion barrels. Such an amount nearly doubles Brazil’s national oil reserves. So far any details about the production rate at the field haven’t been provided, but we can surmise, that the results are satisfying for stakeholders. The New Oil Well Length Record The consortium Sakhalin-1, which operate three fields in the Okhotsk Sea, with ExxonMobil, SODECO, Rosnieft and ONGC stakes, did successfully complete drilling of the world’s longest well. The total length of the well, with its horizontal completion is 15 000 meters. This result was achieved by the use of advanced and extremely efficient technology such as ,,Fast Drill”. According to information provided by ExxonMobil, the technology bases on the use of high quality modeling of physical parameters of drilling combined with structured well planning and design. Including this record, it is worth to mark that consortium Sakhalin-1 drilled nine of the world’s ten longest wells and five of them have been completed since 2013.
The Next Steps Towards Natural Gas Supply Diversification in Poland Growing demand for natural gas in Poland, combined with trend toward diversification of natural gas supply pushes Baltic Pipe forward. The project’s feasibility study was accepted at the beginning of 2017 and the Open Season procedure has been launched in the middle of 2017. The procedure showed that polish market is interested in Baltic Pipe. During economic test at the very end of the year PGNiG- Polish Oil and Gas Company reserved over 90% of the Baltic Pipe transmission capacity. It is expected that till the end of January 2018 PGNiG will sign 15 years transmission contracts with Danish Energinet. dk and Polish Gaz-System S.A. and the next milestone toward pipeline construction will be reached. Meanwhile, a management of Gaz-System S.A. made a decision to develop the LNG terminal in Świnoujście, increasing its capacity from 5 billion to 7,5 billion cubic meters per year. It is going to be achieved by construction of the additional unloading position for LNG carrier and by increasing capacity of the onshore re-gasification facilities. The third LNG tank is planned to be build afterwards. Any exact dates of commencing the investment haven’t been specified yet.
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Sabooh Hasnain, Saad Ahmad, Mohsin Tariq Khan
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Comparative Analysis of Static and Flowing Material Balance on a Low Permeability Gas Reservoir Sabooh Hasnain, Saad Ahmad, Mohsin Tariq Khan * University
Ăž Country
* Reservoir Management Department in OGDCL Ăž Pakistan
pe of decline of average reservoir pressures, thus, by shifting that line upwards it will pass through initial reservoir pressure and will give OGIP. A graphical and quantitative comparison is made between static and flowing material balance. This method is a pragmatic and convenient tool for early quantification of reserves. Introduction
The flowing material balance is simple yet powerful approach especially for low permeability gas reservoirs. It uses flowing data and does not require any shut-in. The data is very inexpensive to gather; it is the data that is measured as a part of good production practice. The conventional material balance (P/Z plots) for gas reservoirs require shutting-in the wells and measuring pressures at different points of time in the life of a reservoir. The plot of P/Z versus cumulative production (Gp) is then generated and straight-line extrapolation of that data leads to OGIP. There are some pitfalls associated with the traditional approach. Especially, in low permeability reservoirs, shut-in time required to stabilize pressures may be too long and it may be unjustifiable due to operational constraints and loss of revenue. The pressures thus obtained will not be true representative of reservoir. This paper demonstrates the successful story of applying flowing material balance to low permeability gas reservoirs and how traditional approach fails in these reservoirs. A plot of Pwf/Z versus cumulative production (Gp) is generated. The slope of decline of Pwf/Z is identical to slo-
To sustain petroleum industry operations, there is a need for positive economics by finding the size of the pool. Reserves are calculated and revised many times during the productive life of the field. This information is critical for the development of depletion strategy, design of surface facilities, economics and in petroleum agreements. The volumetric and material balance estimates gas-in-place whereas decline curve analysis yields expected ultimate recovery (EUR). Volumetric estimates are used early in the life of the reservoir and are usually imprecise as aerial extent of the reservoir is generally unknown at that time. Its certainty may change as more data becomes available through the life of the field. Material balance is by far the best method for quantification of reserves. It is actually a mass balance equation, based on analytical model and incorporates PVT data as well. Once determined, the original gas-in-place (OGIP) can be used to forecast the recoverable gas under different operating scenarios reliably.
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Comparative Analysis of Static and Flowing Material …
Decline Curve Analysis (DCA), on the other hand, is an empirical method based on past production trend. It determines estimated ultimate recovery (EUR) and forecasts future performance of the wells under existing operating conditions. Any change in current operating conditions can alter EUR. Conventional Material Balance For predicting gas-in-place and recovery performance, the use of conventional material balance in the form of P/Z is a powerful tool. The classical material balance equation is actually volume balance equation, i.e. Initial Volume = Vol. Remaining + Vol. Removed For gas reservoirs, plots of P/Z versus cumulative gas production are generated. It provides a convenient method of using average reservoir pressures to estimate OGIP and recoverable reserves once an abandonment P/Z is established. The OGIP is generally considered very accurate after approximately 10–15% of gas reserves have been produced. The usage of P/Z plots has become so ingrained as an industrial practice that vital assumptions behind this technique are often overlooked. In cases, where a reservoir acts like a tank and there is no external maintenance, the relationship between pressure and cumulative gas production is approximately linear. If compressibility factor (Z) is taken into account then the material balance plot is a straight line from initial pressure Pi/Zi, to original gas-in-place (OGIP).
Flowing Material Balance The flow through the porous media can be divided into two major categories: transient and stabilized. The transient flow behavior is dominated by reservoir characteristics such as permeability, skin, boundary location, etc. Stabilized flow, on the other hand, is dominated by reserves. Reservoirs having fair to good permeability, reach the stabilized flow very early during pressure transient testing while low permeability and tighter prospects can take several weeks or months to stabilize and it is uneconomical to shut the well for too long. When a well is in a stabilized flow, its behavior is represented by a pseudo-steady state equation. As a stabilized flow is dominated by reserves, it is possible to estimate the magnitude of the reserves, if gas rate, pressure and time data are available during the period of stabilization. Strictly speaking, flowing material balance is valid only when flow has reached “Boundary Dominated” conditions. The principles underlying this method are best illustrated using constant rate production. When the flow becomes dominated by the boundaries, i.e. stabilized or “pseudo-steady-state” conditions are achieved, the pressure at every point in the reservoir declines at the same rate.
The general gas material balance equation for gas reservoirs is shown below:
The dry gas material balance, having no liquid influx, is reduced to the form shown below:
Fig.1 Drop in a Reservoir as a Function of Radial Distance and Time during Boundary Dominated Flow
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Sabooh Hasnain, Saad Ahmad, Mohsin Tariq Khan
This is illustrated in Figure 1, which shows that pressure drop measured at wellbore is the same as the pressure drop that would be observed anywhere in the reservoir, including the location which represents average pressure. PR1, PR2 and PR3 represent the average (static) reservoir pressure that would be obtained if the well was shut-in at time t1, t2 and t3. It is evident from Figure 1 that the change in average reservoir pressure is equal to the change in the sand-face flowing pressure: (1) (2)
Fig.1 The Flowing P/Z Plot at Constant Rate Production
Rearranging, (3) Thus, if sand-face flowing pressure and average reservoir pressure are plotted versus time (or cumulative production), they will have the same trend, and will be displaced by a constant. In a conventional material balance calculation, reservoir pressure is measured or extrapolated based on stabilized shut-in pressures at the well. While a well is flowing, it is obvious that average reservoir pressure cannot be measured but the above equations represent the relationship between the wellbore flowing pressure (which can be measured) and the average reservoir pressure. Figure 2 demonstrates that Flowing Material Balance technique is applied to a gas reservoir. It shows how the flowing pressures (Pwf/Z) and the average reservoir pressures (PR/Z) are related, and Original Gas-In-Place (OGIP) can be obtained from the flowing pressures if the initial reservoir pressure (Pi) is known. The line drawn through the measured flowing pressure data need only to be shifted upwards so that it passes through the initial (Pi/Zi) point, i.e. both lines have identical slopes.
Time for Stabilization Time for stabilization is defined as the time it takes for the radius of investigation to reach all of the reservoir boundaries. Stabilization originated as a practical consideration and reflected the point at which pressure is no longer changed significantly with time, i.e. it is stabilized. With high permeability reservoirs, it is not difficult to observe. However, in lower permeability and tighter prospects, it takes a very long time for pressure to stabilize, often weeks, months, or even years. Selection of the test type depends on the stabilization time of the well, which is a function of reservoir permeability. If a well stabilizes fairly rapidly, a conventional flow-after-flow test can be conducted. For lower permeability and tight wells, an isochronal test may be preferred. For wells with very long stabilization times, a modified isochronal test may be more practical. The stabilization time for a well in the center of a circular or square drainage area may be estimated from: (4)
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Comparative Analysis of Static and Flowing Material‌
Case Study Initial Reservoir Conditions
A single, centrally located, vertical well is used to deplete the reservoir. The reservoir is pocket-sized, having low permeability, producing dry gas from one well named (X1). The well is producing at a constant choke size, i.e. 24/64�, since commencement of its production. The original gas-in-place has been estimated through volumetric analysis. The initial reservoir parameters are given in TABLE 1 below. Three static bottom hole pressure surveys were conducted during life cycle of the well, which yielded average reservoir pressures. A conventional P/Z graph was generated by plotting P/Z versus cumulative gas production (Gp) and a value for OGIP was obtained as shown in Figure 3.
P (psi)
Z
P/Z
Gp
Initial Gas in Place
4.6 BCF
(Volumetric Method) Initial Reservoir
984 psi
Pressure Initial Reservoir
1220F
Temperature PVT Properties Gas Gravity
0.689
N2
30.4 2%
CO2
0.84%
H2S
0%
(MMscf) 984
0.98
1004.082
0
802
0.975
822.5641
690
706
0.985
716.7513
1137.5
Reservoir Properties Mid Perforation
1920 ft
depth
Tab.2 Parameters for Conventional P/Z
TVDSS
2000 ft
Net Pay Thickness
16 ft
Average
3 mD
of Well X1
Permeability Average Porosity
15%
Initial Water
25%
Saturation Skin
Fig.3 Conventional P/Z Plot of Well X1 Tab.1 Reservoir Parameters The OGIP came out to be 3953.45 MMSCF or 3.9 BCF.
1.7
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Sabooh Hasnain, Saad Ahmad, Mohsin Tariq Khan As the reservoir has lower permeability, as shown in TABLE 1, identified from core analysis, a crosscheck was performed, and in order to do so the time of stabilization was determined first, which enabled to check the validity of measured static pressures. Using a set of reservoir properties given in TABLE 1, the stabilization time calculated with Equation 4 came out to be 174 hours. The shut-in time of a SBHP Survey was 4 days (96 hours), taken as an analogue of offset data of nearby wells. Furthermore, the bottom hole pressure vs. time graph indicated that the pressure is increasing at the rate of 0.71 psi/hr (17.4 psi/day), and this shows that the reservoir pressure is far from being stabilized due to lack of sufficient build-up time. This proved that the conventional material balance yielded imprecise estimates which are misleading.
The first and foremost condition for applying flowing material balance approach is the achievement of Pseudo-Steady-State (PSS) by the reservoir. Since obtaining well head flowing pressures is a part of regular production practice, they are easily available. Well Head Flowing Pressures (WHFP) are converted into Bottom Hole Flowing Pressures (BHFP) using Modified-Cullender & Smith method, which incorporates flow rates, tubing length and diameter, tubing roughness and well head flowing pressures. The gas compressibility factor (Z) is calculated by Carl-Kobayashi-Burrows correlation, which utilizes full gas composition and takes into account the presence of impurities and gives more accurate results. The FMBE calculations are performed with help of Ryder Scott software and excel-based approach.
Date
WHFP
BHFP
Z
Pwf/Z
Gp
May-16
598.80
643
0.955
673.65
67.64
Jun-16
573.80
618
0.956
646.44
142.04
Jul-16
567.87
611
0.956
638.85
218.16
Aug-16
563.12
606
0.957
633.36
293.31
Sep-16
556.50
600
0.957
626.89
367.51
Oct-16
560.00
603
0.957
630.16
439.87
Nov-16
526.53
589
0.958
614.95
515.58
Dec-16
515.51
558
0.960
581.37
590.85
Jan-17
514.13
556
0.960
579.23
655.69
Feb-17
516.44
558
0.960
581.37
708.29
Mar-17
497.25
546
0.961
568.39
746.15
Apr-17
474.36
502
0.963
521.07
782.79
May-17
452.09
479
0.965
496.42
827.29
Jun-17
446.9
474
0.965
491.04
866.70
Jul-17
444.45
471
0.966
487.83
905.54
Aug-17
446.00
473
0.965
490.00
944.12
Sep-17
443.00
470
0.960
487.00
965.93
Tab.3 Flowing P/Z Data of Well X1
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Comparative Analysis of Static and Flowing Material‌
Fig. 4 Flowing P/Z Plot of Well X1
A plot of Pwf/z vs. cumulative production is generated. The slope of decline of Pwf/z is identical to the slope of decline of average reservoir pressures. Both lines have identical slopes, i.e. -0.2132, which illustrates the fact that pressure drop measured at wellbore is the same as the pressure drop that would be observed anywhere in the reservoir. So, by shifting that line upwards, it will go through Pi/Zi and will give OGIP as illustrated in Figure 4. Thus, it is evident that using traditional P/Z plots dramatically underestimate the size of reservoir in the case of low permeability reservoirs. As this is a pocket-sized reservoir, the impact of erroneous results will be far greater in tight reservoirs with large aerial extent. One obvious alternative solution to the material balance problem in low permeability reservoirs is to use reservoir simulation, but in this case, the time and expense for simulation is not justified.
Conclusion The comparisons of results are summarized below: Volumetric Estimates 4.60 BCF Static P/Z 3.95 BCF Flowing P/Z 4.93 BCF The results show that since it is a lower permeability prospect, the conventional material balance renders the results invalid as indicated by insufficient time of stabilization to reach average reservoir pressures. The static material balance has yielded underestimates. The percentage error between the results of conventional and flowing material balance is around 20%. Hence, FMBE comes to the rescue. It is a more reasonable approach to apply in the case of lower permeability reservoirs and OGIP estimates are much closer to volumetric estimates.
11
Sabooh Hasnain, Saad Ahmad, Mohsin Tariq Khan The flowing material balance is an indirect method for finding average reservoir pressures, so it should not be deemed as the replacement for conventional material balance but as a very inexpensive supplement to it. The Way Forward The flowing material balance can also be applied in the case of reservoirs that are producing at variable rates. No reservoir can produce at a constantly choke size for extended periods of production, besides other parameters such as water breakthrough, which affects the behavior of well head flowing pressures, and in-turn, which affects bottom hole flowing pressure influencing adversely the results, and this loop goes on. Hence, the Dynamic Material Balance applies to variable rate production. It is an extension of the Flowing Material Balance method, which was limited to a constant rate situation. The flowing material balance proves its mettle as it provides no well down time and is economically sound. The gas wells producing sufficient amount of water cannot be shut-in, as this would lead to water loading phenomenon, which may restrict the gas flow partially or fully. Here flowing and dynamic material balance play their part.
What is more, this approach is practical since Pakistan has about 40 TCF of unutilized low permeability and tight gas reserves. Flowing material balance works better for low permeability reservoirs as stabilization occurs with the well flowing. It also makes it possible to determine OGIP with reasonable certainty when shut-in pressures are not available for good permeability reservoirs. Nomenclature Pi = Initial reservoir pressure, psi PR = Average reservoir pressure, psi Pwf = Flowing pressure at interface, psi q = Production rate, MMscfd Z = Gas compressibility factor Zi = Gas compressibility factor at initial reservoir pressure G = Original gas in place, MMscf Gp = Cumulative gas produced, MMscf t = Time, days ts = stabilization time, hrs Ct = total compressibility, psi-1 k = Reservoir permeability, mD h = Pay thickness, ft Φ = Hydrocarbon filled porosity, % μ = Viscosity, cp A = Reservoir Area, ft2
References: [1] EARLOUGHER, R.C., Advances in Well Test Analysis; Monograph Volume 5, SPE-AIME, 1977. [2] SPE-17306-MS: Modification of the Cullender and Smith Equation for More Accurate Bottomhole Pressure Calculations in Gas Wells. [3] David A. Payne, 1996, SPE 36702-PA, Material-Balance Calculations in Tight-Gas Reservoirs: The Pitfalls of p/z Plots and a More Accurate Technique. [4] Mattar, L., McNeil, R., The ‚Flowing’ Gas Material Balance; Journal of JCPT, Vol. 37 #2, page, 1998. [5] Lee, J., Spivey, J. P., Rollins J. B., Pressure Transient Testing; SPE Textbook Series Vol.9, pg. 15, 2003. [6] E.R.C.B. Gas Well Testing – Theory and Practice; Energy and Resource Conservation Board, Alberta, Canada, 1975, Third Edition. [7] JCPT, The Flowing Gas Material Balance by L. Mattar and R. McNeil, Fekete Associates Inc.
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!
Annual Technical Conference and Exhibition in San Antonio 2017
Annual Technical Conference and Exhibition in San Antonio 2017
On 9–11 October, the Society of Petroleum Engineers (SPE) hosted global exploration and production professionals for the 2017 Annual Technical Conference and Exhibition (ATCE) at Henry B. Gonzalez Convention Center in San Antonio, Texas, USA. During the 93rd annual event, 2018 SPE President Darcy Spady received the presidential gavel and officially commenced his presidency of the not-for-profit professional association.
Khaled Al-Buraik, vice president for Saudi Aramco; Deborah Wince-Smith, president and CEO of the Council on Competitiveness; and Franklin Orr from Stanford University.
SPE’s premier technical conference, ATCE presented best practices and emerging technologies to the attending engineers, scientists, academia, managers and executives. The conference’s international exhibiting companies featured a broad range of technological innovations, new products and valuable industry services. ATCE 2017 featured nearly 400 technical papers in 46 technical sessions, plus panels and ePoster sessions.
Simonelli built on the idea of creativity by including the concept of disruption. “I think, as an industry, we’ve got to embrace disruption,” he said, adding, “How do we embrace that disruption and change much faster?”
“It was wonderful seeing SPE members from around the world this week, particularly our Gulf Coast members following the recent devastation of Hurricane Harvey,” said 2017 SPE President Janeen Judah. “From our session focused on learnings following the recent natural disaster to sessions on digital energy, ATCE once again delivered subject matter important to our members, industry professionals, the public, and the environment.” Five panelists discussed “Sustainable Oil and Gas: Improving People’s Lives” in front of a packed ballroom at the Opening General Session. The panel was moderated by Eithne Treanor, ETreanor Media, and comprised Lorenzo Simonelli, chairman and CEO of Baker Hughes, a GE company; David Hager, president and CEO of Devon Energy;
Tackling the challenges of sustainability, Hager said, requires creativity. “Creativity is at the heart of everything we do,” he said. He added later, “To do things tomorrow the way we do things currently is not going to provide the sustainability we need.”
Overall, more than 8,300 professionals from 60 countries attended this year’s event. Sessions focused on subjects such as creating databases of multiple data streams for analyzing how to improve performance and how R&D may be the key to companies’ survival. Speakers, including representatives from operating companies, governmental agencies and global leaders addressed commercializing digital controls and automation. Also on Monday, Vicki Hollub, president and CEO of Occidental Petroleum Corporation, spoke at the Chairperson’s Luncheon. She cited three technologies that, although not new, have played a significant role in upstream development. Seismic imaging, horizontal drilling, and hydraulic fracturing all have succeeded in revolutionizing upstream practices. “The point is, you don’t to have to go too far for new ideas,” she said. “We are seeing the benefits of all three of these technologies at Occidental, most recently in our Permian Basin position.”
13 SPE’s Annual Reception and Banquet recognized individuals for their significant contributions to the oil and gas industry and SPE, while the President’s Luncheon offered the “State of the Society” address from Judah, who also passed the presidential gavel to Spady during the event. An active SPE member since graduating from university, Spady most recently served on the SPE International Board as regional director for Canada and is the first Canadian elected as SPE president. “While we’re confronted with a constantly changing industry landscape, SPE continues to fulfill its mission of collecting, disseminating, and exchanging technical knowledge as exhibited by ATCE 2017. It delivered one of the most innovative, forwarding thinking conferences in its nearly century long history,” said Spady. “Though innovation and technology remain a core focus of this organization, the environment and community are also an essential part of our DNA for SPE members young and old – it is not a simple matter of choosing economy or environment, instead we choose both. As SPE’s new president, one of my main objectives will be to continue pushing these dialogues and actions across our society for the betterment of our industry and world.”
In addition to this, on the 9th of October in San Antonio there was held the PetroBowl competition. After a tough quarterfinal battle with Batangas State University from Philippines, team representing AGH UST ended their PetroBowl adventure at quarterfinals as the best team in Europe and one of the eight best in the World! After this great success, there came time for another event connected with our section. President of our chapter had the opportunity to accept the Outstanding Student Chapter Award from Darcy Spady for the whole effort that we had put this year into our student chapter. We would like to thank our sponsors GAZ-SYSTEM S.A. and United Oilfield Services, as well as CRUX Fine Selection – partner of our chapter. Thanks to them we had the opportunity to participate in such a prestigious event as the ATCE Conference. The 2018 ATCE conference will be held on 24–26 September in Dallas, Texas, USA. For more information, visit www.atce.org.
Fig. 1 AGH UST SPE Team
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Annual Technical Conference and Exhibition in San Antonio 2017
Fig. 2 Former Chairman of SPE AGH, Wojciech Cieplak
Fig. 3
15
Kon Aguek Deng
!
Application of Chemostragraphy to Petroleum Exploration & Field Appraisal in South Sudan: An Example from from Melut Basin* Kon Aguek Deng
* Department of Petroleum Engineering and Earth Science, University of Petroleum & Energy Studies Þ Dehradu
discovered and developed using the information which was collected from the field in Muglad basin and analyzed in KDMIP core lab. In this paper we will discuss the data collected and the result and how it used to develop ONGC fields in South Sudan. Introduction
* This paper was prepared for presentation at the UPES SPE Fest 2017 [9–11 February 2017] The geochemistry of sedimentary rocks is a product of their provenance, maturity and digenetic history. Chemostratigraphy in the variation in major and trace element abundance in sedimentary rocks as a correlation tool. It is particularly relevant in field appraisal where seismic and biostratigraphic methods often have insufficient resolution and data for further development of the oil field, Chemostratigraphy was used to explore and helped develop most of the oil fields in South Sudan and North Sudan, where it is not possible to access location of exploration and well sites, because there is no road or other logistic problems occur. Geologists drill at different locations and collecte core and formation samples, which are then taken to the lab to determine their chemical, mineral composition and the percentage of oil and gas in the porous paces of the rock sample at each location the sample was taken from. Afterwards, geologists will draw both surface and subsurface contour map of basin based on oil and gas percentage in each location where a sample was collected, the contour map and seismic data will give clear information of the reservoir and the location of hydrocarbon. Two fields in South Sudan were
Chemostratigraphy involves the application of trancing chemical and hydrocabone elements for the characterization and subdivision of sadimantry rocks and sequences into geochemically district units, and it’s also important for correlation of strata in sedimentray basins. The geochemical correlation between wells can be established by the identification of similar geochemical characteristics. The chemostartigraphy methods of exploration and formation analysis were used in South Sudan in the largest oil field in the Basin, that is the Great Palogue Field, with estimated reserves of 900 million barrels. Melut oil export pipeline is one of the largest pipeline networks in Africa as it travels from Palogue to port Sudan in North Sudan on the Red Sea for about 1,380 km. In 2008 PetroDar started exploration and production operations in blocks 3 and 7, which are oil concession areas in Melut Basin in South Sudan. Oil and Natural Gas Corporation (ONGC-Videsh) of India is also operating in South Sudan together with CNPC of China and Petronas of Malaysia, as part of the ongoing exploration and field development process in South Sudan. ONGC Videsh collected samples from different oil wells and from different locations for analysis purposes. The samples were brought to KDMIPE core analysis lab to
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Application of Chemostragraphy to Petroleum Exploration & Field Appraisal‌
determine the amount of hydrocarbon (Bitumen and kerogen) and also chemicals and minerals associated with the cap rocks and reservoir rocks for-
mation in order to understand better the reservoir and propose a development plan for the wells and to the field in general.
Fig. 1 Melut Basin in South Sudan
Aims
Reservoir of Melut Basin
1. To apply Chemostratigraphy in exploration and determination of source rock potential, quality and maturity. 2. To study the Chemostratigraphy exploration method and in particular its application in South Sudan by Oil and Natural Gas Corporation (ONGC-Videsh) and to study the Chemostratigraphy of Melut Basin in South Sudan and to study the geology of the basin
From the Chemostratigraphy studies from the samples collected from Melut Basin, we concluded that the primary reservoir basin of Melut Basin are Paleogene and upper Cretaceous sandstones. They served for testing commercial oil flows. The crystalline and metamorphic rock basement of lower relief after a long period and more intense weathering before cretaceous decided the quartz contribution to the sandstone in Melut Basin. The
17
Kon Aguek Deng sandstone exhibits good reservoir quality (porosity and permeability) at the depths in Melut Basin as shown in the Fig. 2. However, different locations and tectonic evolution history resulted in the major pay zone and feature changes with time and space in South Sudan.
tance of Graptolite, Chitinozoans, Scolecodonts and bitumen can be measuredand subsequently converted to a vitrinite Ro equivalent for comparative purposes.
Upper Cretaceous Reservoir Rocks of Melut Formation
◀ Measurement of reflectance with depth to determine maturity. ◀ Less than 0.6 refectance is considered as immature stage. ◀ 0.75 to 0.9 is considered as the peak oil window. ◀ 0.9 to 1.3 is post mature stage. ◀ 1.3 to 2 wet gas. ◀ 2 to 4 is dry gas.
The Melut Formation has a high sand net-to-gross ratio (based on Vsh <50%), ranging from 55% to 83%. Petrographics analysis of percussion sidewall cores indicates that the majority of the reservoir sands may be classified as arkoses, based on Folk’s sandstone classification. Grain size ranges from fine to coarse grained. Framework constituent consists of sub-angular to sub-rounded polycrstaline quartz (41–83%). Feldspar (0–45%) and rock fragments (4–41%) consist of metamorphic quartzite. High content of metamorphic rock fragments and quartz composition confirm that the sediments proven is mainly epimetamorphic rocks. The inclusion homogenization temperature of quartz overgrowth in the sandstone is about 90–130 ºC. The common and strong quartz overgrowth and amkerite repacing indicate that the Melut reservoirs in the Melut Basin are located in the mesodiagenesis. The reservoir quality of the Melut sands is lithofacies-dependent. Porosities of the reservoir sandstone of Melut formation rangs from 8–25%. Average 20%, and permeabilities range from 0.1 to 300 Md. Lab analysis of cores from the Melut Sand intervals show that the average porosity of reservoir is 20.15% and average permeability is 9Md. Calibrated by core study, well logging data indicated that the Upper Cretaceous reservoir belongs to medium porosity and low permeability reservoir. Vitrinite Refelection (VRo) Vitrinite Refelection (Vitrinite – from the cellulose part and usually gray in color) provides an assessment of thermal maturity in rocks younger than from the Devonian Age. VRo measurements are necessary compliment to SRA and TOC analysis. In rocks older than from the Devonian Age, reflec-
The following are considered in the VRo Lab
Fig. 2 Sampel under Vitrinite Refelection
Experimental Procedure The following steps have been taken in the core lab to analyze the samples collected from Melut Basin. 1. Sample collection The core samples brought to the KDMIPE Core lab were sampled in Melut Basin by ONGC Videsh at different wells and depths. The core samples are stored in the core library in controled room conditions. 2. Wash and Dry The samples are brought from the core library to the cleaning room and they are washed with water to remove the impurities. After washing the core samples, they are dried at room temperature.
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Application of Chemostragraphy to Petroleum Exploration & Field Appraisal…
3. Sample Grind (Rock Grind) After the core sample has dried at room temperure, the samples are crushed to powder and screened through BSS 60 mesh sieve before analysis. 4. Rock Eval-6 The crushed samples were analysed on RE-VI for evalutation of source rock potential, quality and maturity. O – 5%
Insignificant
5 – 10%
Poor
10 – 15%
Fair
15 – 20%
Good
20 – 25%
Excellent
Tab.1 Porosity Table [1]
Melut Basin Case Study Core Sampel from Formation (A) Identification and characterization of source rock in wells to prioritize exploratory effort through identification of source rock. A total of 106 cutting samples from 1860–2435m depth interval were studied. The sediments in the depth interval 2005–2010m and 2430–2435m indicate very good amount of organic matter richness (TOC: ranges from 2.69–2.96%) with good amount of remaining hydrocarbon generation potential (S2: ranges from 5.31–7.52mg HC/g Rock). Thermal maturity (Tmax: 425–429 ºC) suggests that the sequences are at immature stage. Rest of the requence is devoid of organic matter richness except for those at the depth intervals 2000–2005m, 2015–2020m that show fair amount of organic matter (TOC %: 0.5–0.66) with very low amount of generation potential. The formation (A) has got type-III organic matter (average HI: 97 mg HC/TOC). Core Sample from Formation (B) A total of 165 cutting samples from 2435–3250m depth interval were studied. The source rock characterization of Formation (B) are discussed below.
1. 2440–2470 m The sediments in this depth interval indicate good to excellecnt organic matter richness (TOC: ranging from 1.36–29.73%, Average TOC: 11.29%) with poor to excellent hydrocarbon generation potential (S2 ranges from 1.08–34.45 mg HC/g rock with average S2: 26.43 mg HC/g rock) the sediments are immature. 2. 2485–2555 m The sequence contains onaverage excellent organic matter richness (Average TOC: 23.63%) and average excellent amount of hydrocarbon generation potential (Average S2: 70.63 mg HC/g rock). Maturity data indicates that the sequence is at immature stage. 3. 2580–2835m The sequence contains average excellent organic matter richness (Average TOC: 19.18%) and average excellent organic matter of hydrocarbon generation potentials (average S2: 42.75 mg HC/g HC). Maturity data indicates that the sequence is at immature to early maturation window. Conclution ◀ Chemostarigrphy may not give the final conclusion for the decision making for the development of the field but it definitely conforms the logging data and the seismic data, it is applicable in places like South and North Sudan, where where seismic data is hard to obtain and sometimes not clear ◀ The Rock Eval and TOC data of the cutting samples of formation A in the depth intervals 2005–2010 m and 2430–2435m have got very good amount of organic matter with good amount of remaining hydrocarbon generation potential and these sequences are at immature stage. The formation A possesses Type–III organic matter (average HI: 97 mg HC/TOC). ◀ The Rock Eval and TOC data of formations B in the depth intervals 2440–2470m, 2485–2555m, 2580–2835m, 2580–2835m, 2920–3090m and 3115–3195m show good to excellent organic matter with good to excellent remaining hydro-
19
Kon Aguek Deng carbon generation potential and these sequences are at immature to mature stage. The formation B possesses Type â&#x20AC;&#x201C;III organic matter (average HI: 155 mg HC/TOC). Nomenclature:
PI: Production Index HI: Hydrogen RC (Co): Residual carbon OI: Oxygen Index PC: Polymer Carbon org (% Weight) Acknowledgements
S1: Gas and free oil content S2: Petroleum potential or hydrocarbon cracked during the pyrolysis Tmax: Temperature measurement at the apex of S2 (Maturity parameter) S3 (CO2): Co2 already present in the sample S4: Residual Carbon S5: Mineral Carbon TOC: Totall Organic Carbon
We would like to give especial thanks to the head of Petroleum Engineering and Earth Science Department, Dr. D.K Gupta and our course coordinator Dr. Pushpa Sharma, who both worked hard to give us a training in Mehasna oil field, Gujrat. And in KDMIPE core and geochemistry lab, we acquired enough field experience and R&D knowledge for us to write this paper.
References: [1] Dr. Pushpa Sharm, UPES, Department of Petroleum Engineering and scienc. Resevoir Engineering notes. [2] PG of the Melut Basin and the Great Palogue Field, Sudan (Marine and Petrol Geol). [3] Ajout Simon, Source Rock Indentifcation and significance in Hydrocabone Exploration, KDMIPE Core Lab Training 14th December 2016. TABLES & FIGURES: Kerogen can be classified by its source material Kerogen Type
Source material
General environment of deposition
1
Mainly Algea (oil prone)
Lacustrine setting (abundant)
2
Mainly plankton, some contribution
Marine setting (moderate)
from algae (oil and gas prone) 3
Mainly higher plants (gas prone)
Terrestrial setting (small)
Reworked, oxidized material (Neither 4
(primarily composed of vitrinite)
Varied settings (none)
or inert material)
Tab.2 [3]
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Application of Chemostragraphy to Petroleum Exploration & Field Appraisal…
Source Rock Evaluation Criteria:
Source rock quality
TOC, %
Pyrolysis S2, mg
EOM
hydrocarbon/g
weight, %
Hydrocarbons, ppm
rock None
<0.5
<2
<0.05
<200
Poor
0.5 to 1
2 to 3
0.05 to 0.1
200 to 500
Fair
1 to 2
3 to 5
0.1 to 0.2
500 to 800
Good
2 to 5
5 to 10
>0.2
>1,200
Very Good
>5
>10
Tab.3 [3] Product Type
Hydrocarbon index
Gas
50 to 200
Gas and oil
200 to 300
Oil
>300
Depth Interval (m) 1860–1865 1865–1870 1870–1875 1875–1880 1880–1885
Tab.4 [3]
1885–1890 1890–1895 1895–1900
Stage
T max
1900–1905 1905–1910
Onset of oil Type I kerogen
445C
Type II kerogen
435C
Type III kerogen
440C
1910–1915 1915–1920 1920–1925 1925–1930 1930–1935 1935–1940
Tab.5 [3]
Fig.2 Photomicrographs illustrating the melut
1940–1445 1945–1450 1950–1455 1955–1460 1960–1465 1965–1470 1970–1475 1975–1480 1980–1485 1985–1490 1990–1495 1995–2000 2000–2005 2005–2010 2010–2015 2015–2020
Tab.6 [3]
]
21
Kon Aguek Deng mineral composition and main diagenetic phases encountered within the Upper Cretaceous Melut Formation (A) Arkose (2679m, Miyan-1 Well, Melut Formation), filled by ankerite repacing and then quartz overgrowths surrounding the framework grains and kaolinite in pores. (B) Yabus Subarkose (1213.79m, Fal-2 well) with quartz overgrowth on the floating grains of quartz and well-developed pores filled by kaolinite. (C) SEM of Yabus subarkose (1213.79m.
fal-2 well) with autogenetic kaolinite in the pore. Quartz and well-developed pores filled by kaolinite. (D) Yabus subarkose (1223.59m. Fal-2 well) overgrowth on the floating grains of quartz and well-developed pores filled by kaolinite and intracrystal pore. Note: AK: Ankerite: F, Feldspar: K, Kaolinite: P, Pore: Q, Quartz: QOG. Quartz overgrowth.
Tab. 7 Well Data Table S1
S2
Tmax
TOC(%)
HI
OI
PI
(mg HC/g rock)
(mg HC/g
(C)
Total Organic
(mg HC/g
(mg CO2/g
Production
Mineral
Carbon
TOC)
TOC)
index
Carbon
rock)
MINC(%)
0.05
0.16
302
0.21
76
333
0.25
0.25
0.04
0.09
330
0.17
53
376
0.28
0.57
0.04
0.1
346
0.16
62
394
0.28
0.27
0.05
0.12
339
0.19
63
258
0.29
0.58
0.04
0.19
314
0.26
73
231
0.19
0.11
0.04
0.16
306
0.19
84
247
0.18
0.08
0.02
0.04
325
0.13
31
400
0.36
0.96
0.01
0.04
321
0.11
36
182
0.29
0.12
0.02
0.07
299
0.19
37
247
0.26
0.11
0.02
0.05
353
0.15
33
300
0.33
0.17
0.02
0.09
319
0.24
38
129
0.17
0.18
0.02
0.08
326
0.25
32
216
0.18
0.23
0.03
0.16
303
0.35
46
114
0.16
0.22
0.04
0.07
323
0.25
28
248
0.36
0.35
0.1
0.37
303
0.45
82
156
0.21
0.26
0.08
0.26
300
0.42
62
121
0.23
0.34
0.04
0.16
326
0.33
48
270
0.2
0.65
0.06
0.16
300
0.15
107
327
0.26
0.11
0.05
0.18
331
0.28
64
314
0.2
0.24
0.04
0.06
289
0.11
55
718
0.37
0.02
0.04
0.16
315
0.11
145
591
0.22
0.03
0.02
0.08
329
0.09
89
289
0.22
0.01
0.09
0.4
328
0.2
200
560
0.19
0.02
0.05
0.26
334
0.11
236
409
0.16
0.02
0.18
0.77
409
0.36
214
272
0.19
0.13
0.06
0.28
337
0.3
93
213
0.18
0.14
0.02
0.07
299
0.16
44
112
0.22
0.21
0.03
0.1
328
0.26
38
96
0.21
0.21
0.08
0.53
417
0.5
106
138
0.13
0.22
0.28
5.31
429
2.69
197
43
0.05
0.17
0.02
0.27
486
0.32
84
0.08
3.88
0.29
1.65
415
0.66
250
279
0.15
0.2
0.12
0.83
336
0.38
218
863
0.13
0.32
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!
Fly Ash Nanoparticles Enhance Foam Stability Performance in SDS – Stabilized Foam
Fly Ash Nanoparticles Enhance Foam Stability Performance in SDS – Stabilized Foam Josiah Wong Siew Kai, Dr Wan Rosli Wan Sulaiman Background of the study
* Faculty of Chemical Engineering and Energy Engineering, Universiti Teknologi Þ Malaysia
Foam Enhanced Oil Recovery (EOR) has been employed as an improved recovery method due to its best sweep efficiency and best mobility control. The major concern of Foam EOR is its foam stability performance when it comes in contact with oil. In this study, the use of fly ash Nanoparticles as a stabilizer to generate stabilized foam was investigated. Fly ash, an inexpensive and available abundantly as a by-product of coal power plants, proved to be an economical and sustainable material to improve foam stability performance. However, it was difficult to generate stabilized foams without any addictive. Therefore, with the use of the addictive such as surfactant Sodium Dodecyl Sulfate, SDS, a stable and dense foams are produced. Throughout the experiment, we have studied the formability and stability of the foam produced. In the presence of oil, the foam stabilized by fly ash nanoparticles and SDS surfactant (nano-ash-SDS foam) shows a higher stability performance. We have also investigates the effect of SDS and fly ash concentration on foam stability performance. It was observed that bulk foam that contains small amounts of nano-ash particles shows a higher stability in the presence of oil.
Oil and Gas Industry has been entering a new technology era when all the problems from the previous decades can be resolved using the emerging technologies. Years ago the oil could not be recovered, now it has been recovered using Enhanced Oil Recovery (EOR) technique. EOR has proved to be the greatest solution to non-recovery oil. Year by year, EOR keeps improving and many new methods have been developed and applied in field. One of the well-known method is Foam EOR and this has been widely implemented by using carbon dioxide gas, nitrogen gas or natural gas to generate foam needed in foam EOR. Foam has good sweep efficiency, thus it improves recovery and creates less problems associated with the method. One of the reasons why foam EOR can be so widely implemented is because of its specific gravity-independent properties that do not create the gravity segregation problem, whereas gas flooding has severe gravity segregation and causes fingering channelling problem. However, foam generated is thermodynamically and kinetically unstable under the harsh environment conditions in the reservoir. High pressure and high temperature will degrade the foam quality and thus disrupt the foam stability. Obviously, maintaining the foam stability is important in order to achieve an EOR foam applicable to the field solution. Several approaches have been examined by previous researchers on how to stabilize the foam generated by adding some sort of an addictive. Usually surfactants are found to be the most common and effective agents in the production of stabilized foams. However, surfactant-based foams are subjected to degradation due to absorption and retention on the reservoir rock, which lead to an increase in material costs. High salinity and temperature
Josiah Wong Siew Kai, Dr Wan Rosli Wan Sulaiman
23
also affected the stabilization of surfactant-based foam. Thus, it is challenging to keep up a long-term stability for surfactant-based foams during field application. When it is in contact with residual oil, surfactant foam appears to be unstable before it manages to perform better sweep efficiency. Thus, to improve the foam stability, sometimes costly surfactant are pump in more to the reservoir to generate foam needed which is significantly costly. Therefore, it is very significant to find the alternative of such a substitution material as a foam stabilizer in stabilizing the surfactant-foams.
study the mechanism of the foam interaction with oil with the aid of fly ash nanoparticles. The result obtained will be useful in the application of this technology, which requires inexpensive alternative nanoparticles that can be produced in large volumes or foam stabilization in field-scale. Utilization of fly ash for this purpose would bring significant economic and environmental benefits. The result obtained later will be useful in the screening method of practicality foam flooding with nanoparticle for future EOR’s operation due to the rise of miscible flooding nowadays.
A solution to this problem is to use solid particles in stabilizing foams. Practically, nanoparticles are of great interest in forming emulsions and foams because they can generate extremely stable CO2 foam capable of enduring harsh reservoir conditions and reducing the in-situ mobility (Lee et al., 2015). The foams made from solid nanoparticles are stable over long periods (up to a year), in contrast with foams stabilized by surfactant molecules the lifetime of which is of a few hours (Alargova et al., 2004). The pioneering study was conducted by Dickson et al. (2004), who used surface-modified silica nanoparticles to generate stable CO2 foams in water solution. Binks and Horozov (2005) successfully used silica nanoparticles to stabilize aqueous foam. Zang et al. (2011) also used silica nanoparticles to stabilize both oil and water emulsions and effectively proved that for foam stabilizers in harsh-condition emulsion. Moreover, a very stable supercritical CO2 foams were generated by Espinosa et al. (2010), who used carbon dioxide gases and silica nanoparticles injected together through glass-beads pack. Similar results were shown by Worthen et al. (2013), which proved that nanoparticles stabilized CO2-in-water foams.
Objective
In this experiment, fly ash nanoparticles are used for the study because of their potential of being an economic and sustainable material to stabilize the foam generated. Surfactant Sodium Dodecyl Sulfate (SDS) was used as the foam agent to generate the surfactant-based foam. An optimum concentration of fly ash nanoparticles should be obtained from the laboratory study to avoid wastage of fly ash nanoparticles. In addition, crude oil is added to
Three main objectives of this research are identified: ◀ To identify the performance of the fly ash as a substitution material which proved to be economical, and sustainable materials in stabilization performance. ◀ To identify the stability performance of nano-ash-SDS foam in the presence and absence of oil. ◀ To compare the effect of the fly ash nanoparticles and fly ash particles on the foam stability performance. Methodology Materials The fly ash was obtained as the product of burning charcoal. The organic charcoals produced powder-like form of fly ash after 12-hour burning process in the open air. The powder obtained underwent several sieving before it could be analysed with the use of nanoparticle analyser with zeta potential. As the original fly ashes size is too big, which is 30 µm averagely, therefore the first step was to obtain nanoparticles from the fly ash powder via the ball-milling process. After the ball milling process, the particles were going to undergo size analysis again to confirm the particles as the nanoparticles. Also, the compositional analysis of the fly ash nanoparticle was determined using Energy Dispersed X-ray analysis (EDX) together with morphology studies using scanning electron microscope (SEM). The element and oxide composition was determined using X-Ray Diffraction (XRD). The Fig. 1 and Fig.
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Fly Ash Nanoparticles Enhance Foam Stability Performance in SDS – Stabilized Foam
2 show the SEM analysis of fly ash nanoparticles. The majority of the fly ash nanoparticles are irregular in shape and tend to agglomerate together. From the results obtained in Fig. 3 and Tab. 1, the fly ash sample was classified as class F fly ash after the analysis of its composition. Class F fly ash, which contains less than 20% Calcium Oxide, has an average nano-size of around 300nm after the ball-milling process.
Phase name
Content(%)
Sylvite, syn
21(3)
Calcite, syn
59(7)
Silicon Oxide
13(5)
Calcium Oxide
0.000000
Aluminum Oxide
0.000000
Hematite
0.000000
Periclase
0.000000
Sodium Oxide
0.000000
Halite, syn
7.4(12)
Tab. 1 XRD results for compositional analysis
Nano-Ash Production
Fig.1 SEM-image of ball milled fly ash (in 5um scale)
Reduction in particle size of the fly ash from µm to nm level was achieved by using a high-energy planetary ball milling machine (model DECO-PBM-V-2L-A; DECO, China). The grinding is done in dry and wet medium. First dry grinding was conducted to reduce the particle size that is above the average distribution size 30 µm. After 5 hours of dry grinding, ethanol was added to prevent the hardening of the milled fly ash and to further reduce the size distribution to nano-size level. The ball mill was loaded in the ball to powder ratio of 1:10 in both dry and wet grinding, where 30 grams of powder were milled by 300 grams of ball mill. The ball mill and the milling chamber were made of stainless steel. The ball diameter was 5mm. Rotation speed was 400 rev min-1. After 5 hours of wet grinding, the samples of the milled powder were taken out and dried in a hot oven at 90°C for 15 hours. The final d50 of the nanoparticles was reduced from 30 µm to 300nm. Experiments
Fig.2 SEM-image of ball milled fly ash (in 50um scale)
Foam Stability Test The foam stability test was conducted using the dynamic foam analyser (model KRÜSS DFA100; KRÜSS, Germany). The concentration of fly ash nanoparticles used in this experiment was set at
25
Josiah Wong Siew Kai, Dr Wan Rosli Wan Sulaiman
Fig. 3 EDX results of fly ash nanoparticles 0.0 wt% (SDS only), 1.0 wt%, 3.0 wt%, 5.0 wt%, 7.0 wt% and 10.0 wt% to determine the optimum concentration towards stabilizing SDS Foam. SDS was set at its critical micelle concentration (CMC) value. SDS together with fly ash dissolved in the salt solution, which acts as the resemblance of the Malay Basin Seawater. The solution ingredients are summarized in Tab. 2. The gas was allowed to flow for 12 seconds with the flow rate of 0.3m3/sec to generate the foam. Foam height generated was analysed and captured by the camera. The foam structure was analysed from the picture captured.
The result and graph will be recorded and displayed using foam analysis software. Half-life method was used to evaluate the foam stability, thus the time taken for the foam to disintegrate and the foam height is recorded using the foam analyser software. After determining the optimum concentration of fly ash nanoparticles, the experiment was repeated with n-hexadecane as the resemblance of crude oil added to study the foam-oil interaction. Apart from that, we also studied the foam generation in oil to compare the difference of the foam behaviour in term of foam stability, structure and foaminess. Tab. 2 Ingredients of
Material
Description
Composition
Deionised Water
As liquid solvent
200 ml
NaCl
As brine
2 wt% (20 000 ppm)
SDS
As surfactant
CMC value: 0.23 wt%
Fly Ash
As nanoparticle
1.0 wt%, 3.0 wt%, 5.0 wt%, 7.0 wt% and 10.0 wt%
variable foam formulation
of the desired concentration of fly ash Gas
As Foam Booster
300ml/min with gas density = 1.293kg/m3
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Fly Ash Nanoparticles Enhance Foam Stability Performance in SDS â&#x20AC;&#x201C; Stabilized Foam
Result & Discussion Effect of Fly Ash Nanoparticles on foam stability performance To study the performance of fly ash nanoparticles behaviour on foaming, six samples were prepared, i.e. surfactant alone, and 5 different concentrations of fly ash nanoparticles. The specific weight of the fly ash nanoparticle is shown in Tab. 3. Fig. 4 shows the result of the foam stability performance resulted from the different concentration of fly ash nanoparticles. Fly Ash Nano-
Deionized water
Fly Ash Nano-
-particles (wt%)
(ml)
-particles (g)
1.0
200
2.0
3.0
200
6.0
5.0
200
10.0
7.0
200
14.0
10.0
200
20.0
Tab. 3 The specific weight of the fly ash nanoparticles
Fig. 4 Foam Stability Performance without oil
As show the results presented in Fig. 4, the addition of the fly ash nanoparticles have successfully enhanced the foam stability performance, for which the time for foam height to decrease until the half of the original foam height stability increases with an increase in the foam concentration. This can be further explained with the addition of fly ash nanoparticles; it will increase the stability of foam lamella, thus increasing the strength of the foam lamella itself can be compared to surfactant alone generated foam. The results show that the optimum concentration of fly ash nanoparticles is 10.0 wt%, which works best with the SDS together to stabilize the foam generated. However, 10.0 wt% fly ash nanoparticles + SDS solution were in a very saturated concentration in which it tends to form slurries afterwards. Thus, further increase in fly ash nanoparticles will cause wastage as the additional fly ash nanoparticles will not be able to dissolve in the brine solution and tend to form impurities at the bottom of the bottle. Also, in the field application, the slurries formed are not capable to pass through the pore throat of the reservoir rock, therefore, it will not improve the sweep efficiency. Effect of Fly Ash Nanoparticles on foam structure Fig. 5 shows the foam structure captured from the camera of the foam analyser. Stable foam structure will be in round shape and the size will be relatively smaller compared to others. This can be shown in the picture of nano-ash-SDS foam, which are denser, smaller and rounder than the SDS-generated foam. The colour bubble indicates the average bubble size, where green colour represents the smaller size of bubble, the blue colour and purple colour represent the bigger bubble. The denser the bubble foams, the more significant the strength of the foam lamella, which will cause the foam to stabilize until up to one day plus. On the other hand, the bigger the bubble size, the weaker the lamella, thus, it will be easy to break even under the small wind blow. The unstable foam will be not in round shape, but tend to be in hexagonal or heptagonal shape, making it easier to break or disintegrate.
27
Josiah Wong Siew Kai, Dr Wan Rosli Wan Sulaiman
Fig. 5 Foam Structure Comparison
Effect of Fly Ash Particles and Fly Ash Nanoparticles on Foam Stability Performance To determine the size of the particle as the factor of foam stability performance, the experiment was repeated by using the original fly ash particles which did not undergo the ball milling process. The concentration of fly ash particles used here is 10.0 wt%, which is the optimum concentration obtained from the previous experiment results. The comparison results between fly ash particles and nanoparticles are shown in Fig. 6.
Fig. 6 Foam Stability Performance with size as variable
The trend in the results shows that the size of fly ash did affect the foam stability performance. As the particle size of ball-milled fly ash was lower than the original fly ash, changing the foam stability performance expected, which proves that particle size is also an important parameter for determining the foam stability (B.P.Binks and T.S.Horozov, 2006; T.N. Hunter et al., 2008).
Effect of Alkane type oil on foaming The effect of oil on foaming was studied to identify the foam behaviour when contacted with oil. Alkane type of oil was used in this experiment as the resemblance of crude oil. In this case, n-hexadecane with the density of 0.773 and molecular weight 226.44 was used. Each of the 30 ml solutions prepared was mixed with 10 wt% of n-hexadecane, which is 3.8 ml per solution. The foaming result when contacted with oil is shown in Fig. 7.
Fig. 7 Foam Stability Performance with oil
The foam stability was decreased with the oil added to the foam generated. The oil accelerated the disintegration of the foam, which sped up the half-life of the foam itself. Thus, this is a sign of decreasing half-life for every concentration compared to the studies without adding the oil. The concentration of fly ash nanoparticles used here was SDS alone (0.0 wt% fly ash nanoparticles), 1.0 wt% fly ash
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Fly Ash Nanoparticles Enhance Foam Stability Performance in SDS â&#x20AC;&#x201C; Stabilized Foam
nanoparticles and 5.0 wt% fly ash nanoparticles. In this study, 5.0 wt% is the maximum concentration of fly ash that can be used, as further increasing fly ash concentration will cause slurry formation and lowering the foamability of the solution. The results obtained are positive since the addition of the fly ash nanoparticles still resulted in enhancing the foam stability performance. The mechanism of the nano-ash foam in the presence of oil is not clear. It can be speculated that the presence of nano-ash particles prevents or slows down the oil droplets from entering and breaking the lamellae (Pugh 1996). Effect of foam generation in oil mixture The oil mixture was used to regenerate the foam with the oil content 10.0 wt% of n-hexadecane and nano-ash-SDS mixture. The objective of this sub-experiment is to identify the foam behaviour generated in the presence of oil, but not the reaction of the foam when it comes in contact with oil. The results obtained are shown in Fig. 8.
Fig. 4 Foam Generation in Oil mixture
In accordance with the results obtained, it was found that the performance of fly ash nanoparticles is still better compared to the performance of surfactant alone. Fly ash nanoparticles are still performed in stabilized foam generated from the oil mixture solution. However, foam generated together with
oil has lower stability than foam in contact with oil. This can be explained as the oil itself is not a foaming agent, which means it does not participate in foam generation, thus it will function as impurities which disrupt the foam generation. Conclusion The experimental result showed that the mixture of fly ash nanoparticles and SDS surfactant can be effectively used to generate a stabilized foam. The foamability and foaminess increase with the aid of fly ash nanoparticles by creating a denser and more stable foam structure. The nano-ash-SDS foam generated has a longer half-life than SDS foam, which proved to be more stabilized in the ambient conditions. Thus, in harsh conditions like high pressure, high temperature, we believe that the nano-ash-SDS foam will still function as stable as tested compared to SDS-generated foam. The behaviour of the generated foam in harsh conditions is valuable to be tested in the next research. Different parameters such as temperature, brine salinity, gas injection rate, pH, pressure, CO2 gas or N2 gas-generated foam are also valuable to be tested with fly ash nanoparticles. Our test experiments show that a higher stability occurs with the additional 10.0 wt% of fly ash nanoparticles. In addition, the 10.0 wt% nano-ash-SDS foam is remarkably stronger than the foam generated by the same SDS concentration, which can be identified from the foam structure captured. In terms of size factor, fly ash nanoparticles (post ball-milling) and fly ash micron-particles (pre ball-milling) show different behaviour in stability performance, although they come from the original sources. Therefore, it proved that size is also one of the factors that affected the foam structure and foam stability. In the presence of oil, nano-ash-SDS foam again shows higher stability performance than the foam generated by the same concentration of SDS. The behaviour of foam-interaction with oil is also a valuable study which is related to the surface chemistry. Foam in-situ generation also proved that foam stability increase with the aid of fly ash nanoparticles. In
Josiah Wong Siew Kai, Dr Wan Rosli Wan Sulaiman conclusion, the performance of the fly ash nanoparticles in enhancing the foam stability has been proven in the conducted experiment, which shows that the fly ash nanoparticles will be a valuable, sustainable and economical addictive to the future of foam EOR’s operation.
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Acknowledgement The authors acknowledge the financial support from the Society of Petroleum Engineers (grant reference number 4B191).
References: [1] Ahmad, I., Awang, M., Sufian, S. et al. 2016. Effect of Ball Milling of Fly Ash Particle Size on Foam Stabilization EOR. Jurnal Teknologi UTM, 78(6–7): 115–119, <https://doi.org/10.11113/jt.v78.9101>. [2] Alargova, R. G., Warhadpande, D. S., Paunov, V. N. et al. 2004. Foam superstabilization by polymer microrods. Langmuir, 20(24): 10371–10374, <https://doi.org/10.1021/la048647a>. [3] Binks, B. P. 2007. Colloidal particles at liquid interfaces. Physical Chemistry Chemical Physics, 9(48): 6298–6299. https://doi.org/10.1039/b716587k. [4] Binks, B. P., & Horozov, T. S. 2005. Aqueous foams stabilized solely by silica nanoparticles. Angewandte Chemie - International Edition, 44(24), 3722–3725, <https://doi.org/10.1002/anie.200462470>. [5] Dickson, J. L., Binks, B. P., & Johnston, K. P. 2004. Stabilization of carbon dioxide-in-water emulsions with silica nanoparticles. Langmuir, 20(19): 7976–7983, <https://doi.org/10.1021/la0488102>. [6] Eftekhari, A. A., Krastev, R., & Farajzadeh, R. 2015. Foam Stabilized by Fly Ash Nanoparticles for Enhancing Oil Recovery. Industrial and Engineering Chemistry Research, 54(50): 12482–12491, <https://doi.org/10.1021/acs. iecr.5b03955>. [7] Espinosa, D., Caldelas, F., Johnston, K. et al. 2010. Nanoparticle-Stabilized Supercritical CO 2 Foams for Potential Mobility Control Applications. SPE Journal, 1–13. SPE-129925-MS, <https://doi.org/http://dx.doi.org/10.2118/ 129925-MS>. [8] Hunter, T. N., Pugh, R. J., Franks, G. V. et al. 2008. The role of particles in stabilising foams and emulsions. Advances in Colloid and Interface Science, 137(2): 57–81, <https://doi.org/10.1016/j.cis.2007.07.007>. [9] Latif, W. M. S. B. M. 2015. Effects of Temperature on Titanium Dioxide Nanoparticles Stablized SDS CO2 Foam. MS Thesis, Universiti Teknologi Malaysia, Skudai, Johor (June 2015). [10]. Lee, D., Cho, H., Lee, J. et al. 2015. Fly ash nanoparticles as a CO2 foam stabilizer. Powder Technology, 283: 77–84, <https://doi.org/10.1016/j.powtec.2015.05.010>. [11] Li, H., Chen, Y., Cao, Y. et al. 2015. Comparative study on the characteristics of ball-milled coal fly ash. Journal of Thermal Analysis and Calorimetry, 124(2): 839–846, <https://doi.org/10.1007/s10973-015-5160-5>. [12]. Patil, A. G., & Anandhan, S. (2012). Ball Milling of Class-F Indian Fly Ash Obtained from a Thermal Power Station. International Journal of Energy Engineering IJEE IJEE, 2(2): 57–62. [13] Paul, K. T., Satpathy, S. K., Manna, I. et al. 2007. Preparation and characterization of nano structured materials from fly ash: A waste from thermal power stations, by high energy ball milling. Nanoscale Research Letters, 2(8): 397–404. https://doi.org/10.1007/s11671-007-9074-4. [14] Singh, R., Gupta, A., Mohanty, K. K. et al. 2015. Fly ash nanoparticle-stabilized CO2-in-water foams for gas mobility control applications. Proc., SPE Annual Technical Conference and Exhibition, Houston, Texas 28-30 September, SPE175057-MS, <http://dx.doi.org/10.2118/175057-MS>. [15] Tan, X. K., Sulaiman, W. R. W., & Idris, A. K. bin. 2016. Advances in Gas-Based Enhanced Oil Recovery. Proc., International Graduate Conference on Engineering, Science and Humanities, Skudai, Johor, 15-17 August, 103–105. [16] Worthen, A. J., Bagaria, H. G., Chen, Y. et al. 2013. Nanoparticle-stabilized carbon dioxide-in-water foams with fine texture. Journal of Colloid and Interface Science, 391(1), 142–151, <https://doi.org/10.1016/j.jcis.2012.09.043>. [17] Zhang, T., Espinosa, D., & Yoon, K. 2011. Engineered Nanoparticles as Harsh-Condition Emulsion and Foam Stabilizers and as Novel Sensors. Proc., Offshore Technology Conference, Houston, Texas, 2-5 May, OTC-21212-MS, <https://doi.org/10.4043/21212-ms>.
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Drilling In Natural Gas Hydrate Reservoirs
Drilling In Natural Gas Hydrate Reservoirs Shubham Satyam
Introduction To Natural Gas Hydrates
* University of Petroleum and Energy Studies Þ Dehradun The idea aims at bridging the gap between E&P companies and the recovery of methane from methane hydrates by providing a method that is cost effective, easily constructible and highly efficient altogether. The method suggested has been conceived in accordance with the notorious and unephemeral current condition of oil and gas industry. Methane hydrates are naturally occurring ice-like structures found generally in permafrost and marine environments. The prerequisites for the formation of gas hydrates are cold temperatures and high pressures alongside abundant methane and water availability. Methane, the value of which has gone unrealized until recently, is now being rightly called “The Fuel of the Future.” The Energy Information Administration of USA supports the view that the amount of carbon and hence methane is bigger in hydrates than in every other fossil fuel combined. Unconventional methane gas hydrate can therefore be called as the perfect remedy for all the current complications of the O&G sector. This paper accesses the available technology for drilling in gas hydrate reservoirs, which is sufficient in tapping this abundant resource. Drilling methods include managed pressure drilling (MPD), casing while drilling (CwD) and use of mud coolants during drilling. A mutual application of such methods can help us drill into the ‘difficult’ gas hydrate formations. The novelty of this paper lies in the fact that methane is recovered in huge amounts with a simple approach. Drilling in methane hydrates can be done effectively with the current technology if done carefully.
Natural gas hydrates or Methane hydrates are solid clathrate compounds or clathrate hydrates which are crystalline water-based solids that resemble ice, but in which a large amount of methane is trapped. The hydrates are formed by the release of gas from the breakdown of organic matter deep in rock sediments. This gas then percolates upwards along geological faults, and when the gas is exposed to sufficiently low temperatures and high pressures (i.e. on contact with cold sea water in the deep ocean), it crystallizes and forms weak chemical bonds with the surrounding water molecules resulting in the solid methane hydrate. Both scientists and oil companies have long been aware of methane hydrate; it was typically regarded as a hindrance to offshore operations, and at best simply ignored. But it is now being re-examined in a very different light and being hailed as a potentially massive source of natural gas with the capability to fuel the global economy for decades. Governments and oil companies are rushing to come up with ways to exploit this new resource. It is very early in the evolution of this nascent industry and the jump from laboratory to the real-world operations is only just being made. But research budgets are growing and the pace of development is quickening and if methane hydrate fulfils even part of its potential then its effect on global energy markets will be profound. Stability of Gas Hydrates Gas hydrate stability zone, also referred to as methane hydrate stability zone (MHSZ) or hydrate stability zone (HSZ), refers to a zone and depth of the marine environment at which methane clathrates naturally exist in the Earth's crust.
Shubham Satyam
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Fig. 4 A piece of gas hydrate from the subduction zone off Oregon
Gas hydrate stability primarily depends upon temperature and pressure, however, other variables such as gas composition and ionic impurities in water influence stability boundaries. The existence and depth of a hydrate deposit is often indicated by the presence of a bottom-simulating reflector (BSR). A BSR is a seismic reflection indicating the lower limit of hydrate stability in sediments due to the different densities of hydrate saturated sediments, normal sediments and those containing free gas.
geothermal gradient. Along continental margins the average thickness of the HSZ is about 500m.
The upper and lower limits of the HSZ, as well as its thickness, depend upon local conditions in which the hydrate occurs. The conditions for hydrate stability generally restrict natural deposits to polar regions and deep oceanic regions:
In areas of high geothermal heat flow, the lower limit of the HSZ may become shallower, therefore decreasing the thickness of the HSZ. Conversely, the thickest hydrate layers and widest HSZ are observed in areas of low geothermal heat flow. Generally, the maximum depth of HSZ extension is 2000 meters below the earthâ&#x20AC;&#x2122;s surface. Using the location of a BSR as well as the pressure temperature regime necessary for hydrate stability, the HSZ may be used to determine geothermal gradients.
1. In polar regions, due to low temperatures, the upper limit of the hydrate stability zone occurs at a depth of approximately 150 meters. The maximum depth of the hydrate stability zone is limited by the
2. The upper limit in oceanic sediments occurs when bottom water temperatures are at, or near 0° Celsius, and at a water depth of approximately 300 meters. The lower limit of the HSZ is bounded by the geothermal gradient. As depth below seafloor increases, the temperature eventually becomes too high for hydrates to exist.
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Drilling In Natural Gas Hydrate Reservoirs
Stability of Gas Hydrates Gas hydrate stability zone, also referred to as methane hydrate stability zone (MHSZ) or hydrate stability zone (HSZ), refers to a zone and depth of the marine environment at which methane clathrates naturally exist in the Earth's crust. Gas hydrate stability primarily depends upon temperature and pressure, however, other variables such as gas composition and ionic impurities in water influence stability boundaries. The existence and depth of a hydrate deposit is often indicated by the presence of a bottom-simulating reflector (BSR). A BSR is a seismic reflection indicating the lower limit of hydrate stability in sediments due to the different densities of hydrate saturated sediments, normal sediments and those containing free gas. The upper and lower limits of the HSZ, as well as its thickness, depend upon local conditions in which the hydrate occurs. The conditions for hydrate stability generally restrict natural deposits to polar regions and deep oceanic regions:
1. In polar regions, due to low temperatures, the upper limit of the hydrate stability zone occurs at a depth of approximately 150 meters. The maximum depth of the hydrate stability zone is limited by the geothermal gradient. Along continental margins the average thickness of the HSZ is about 500m. 2. The upper limit in oceanic sediments occurs when bottom water temperatures are at, or near 0° Celsius, and at a water depth of approximately 300 meters. The lower limit of the HSZ is bounded by the geothermal gradient. As depth below seafloor increases, the temperature eventually becomes too high for hydrates to exist. 3. In areas of high geothermal heat flow, the lower limit of the HSZ may become shallower, therefore decreasing the thickness of the HSZ. Conversely, the thickest hydrate layers and widest HSZ are observed in areas of low geothermal heat flow. Generally, the maximum depth of HSZ extension is 2000 meters below the earthâ&#x20AC;&#x2122;s surface. Using the location of a BSR as well as the pressure temperature regime necessary for hydrate stability, the HSZ may be used to determine geothermal gradients.
Fig. 2 Three-phase (liquid water + hydrate + vapor) stability conditions: (a) in the permafrost and (b) in the ocean
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Shubham Satyam Case Study: Summarised Report – National Gas Hydrate Program (NGHP-02): Four wells of Krishna-Godawari basin that were being developed in NGHP phase 2 were studied during the drilling phase and the problems encountered in each well were noted. The observations in each well are as follows: Well A The first well evaluated in this area was drilled in a water depth of 1553m (5094 ft) subsea in deep water Krishna Godavari Offshore with 239mbsf (meter below sea floor) drill out portion. While drilling with 8 1/2" bit for logging while drilling (LWD) well observed high torque and pack-off was suspected at 239mbsf. The kill mud of 1.5 specific gravity (s.g.) was pumped at bottom and string was pulled out to the seabed, ROV (Remote Operated Vehicle) image showed gas bubbles from the well. The well was terminated at around 239 mbsf. It was suspected that openhole instability caused by gas hydrate dissociation may produce zones of decreased shear strength where sediment can become unconsolidated, which results in pack off and gas build-up near hydrates stability zone. A similar phenomenon was observed in several more wells having deeper water depth of 2557m during LWD operation and penetrating hydrate stability zone around 300mbsf. When hydrate dissociates, there is reduction in bottom-hole pressure due to changes in mud density, as dissolved gas mixes with mud and this may lead to an enlargement of a borehole or collapse of a hole. It is concluded that this section might contain gas hydrates zone or may be the presence of free gas based on drilling problems experienced in the hole. Well B Other example is of an area drilled in deep water at a depth of 2219.5m. While drilling with 8 1/2" bit with sea water for continuous coring from sea floor to 2518.5 mbrt (meter below rotary table), the drill pipe connection and survey was going on through hydrate bearing sandstone (HBS) area. It appears that we may have encountered the base of
gas hydrate occurrence at this site near 2515.0 m (267 mbsf). The drilling plan would have had us drilling another 100 meters below this depth in order to get the measurement point on all the logging tools on the bottom hole assembly (BHA) well below the depth of the deepest target of interest. But after reaching a depth of 2518.5 m (270.5 mbsf), the drill string became severely "packed-off ” after drilling through thick sand layer and it took more than five hours to free the BHA from the bottom of the borehole. It was decided to abandon the hole at a total depth of 2518.5 m (270.5 mbsf) because of apparent damage to the LWD BHA and the degrading borehole conditions. Well C This example illustrates difficulties faced during MDT. The objectives of MDT test are to measure formation pressure before dissociation of gas hydrates, downhole fluid identification, fluid sampling and provide dynamic flow data. While attempting first ever deep water MDT testing, the tool reached the reservoir section but it could not enter fully into the formation, which may be due to hole pack off or unconsolidated formation (calliper log shows that hole enlargement – 10 5/8"hole size becomes more than 18"). In the second MDT test , the tool could not straddle pack upper Gas Hydrate area at 2465 Mbrt (217 mbsf) either. Hence, it has been decided to conduct straddle packer test of upper zone. But MDT pump began to fail while trying to inflate packer, which may be due to pack off or wellbore collapse. This indicates that the hole condition worsen due to unconsolidated formation just above the gas hydrate stability zone. Well D Wireline logging tool stuck inside 5-inch drill pipe: while logging FMI (formation micro imager) with wireline at water depth of 1768 m, wireline logging tool got stuck inside 5" drill pipe at 1772 mbrt, i.e. 16m above sea bed surface. It has been observed that the well was flowing with minor gas on ROV camera. Engaged Top drive system was engaged and circulation was attempted to be established but the pressure shot up. An attempt was made to
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34 free wireline from drill string but it was unable for the logging tool to free. After several unsuccessful attempts, it was decided to perform reverse cut and thread fishing operation on wireline. It was observed that hydrate plug was formed inside wireline guide shoe due to suspected dissociated gas, low sea water temperature near sea bed (3–5° C), high hydrostatic pressure (2575psi) and availability of water, which are favourable conditions for formation of gas hydrate plug inside the drill string. Common Problems Encountered in the 4 wells: ◀ ◀ ◀ ◀
Pack-off Hole Enlargement Wellbore Instability Stuck-up due to hydrate dissociation
Based on the above case study, the concluded drilling hydrate related challenges are: 1.Stuck-up taking place due to hydrate dissociation 2 Narrow pressure margins between pore pressure and fracture pressure 3. Hydrate formation inside the equipment such as BOP, wellhead and chokeline 4. Well control for sudden gas influx 5. Pressure fluctuations taking place within the open hole 6. Casings get damaged due to gas expansion taking place and pressure suddenly rising Relevant Solutions Evaluation Of Drilling Methodology A. Overbalanced Drilling OBD involves keeping the pressure at the bottom of the fluid column, the bottomhole pressure (BHP), in the wellbore annulus above the pore pressure of the formation (formation pressure), thus preventing the influx of mobile formation or reservoir fluids into the wellbore. Following problems may arise if conventional overbalanced drilling is used for drilling in hydrate containing sediments:
Drilling In Natural Gas Hydrate Reservoirs
1. OBD is unable to react quickly to temperature and pressure anomalies at any location within the wellbore during drilling This is because the pressure in the well is almost completely controlled by the hydrostatic mud column in the well, which means that adjusting the pressure in the well requires the time-consuming process of changing the density of mud and then circulating it into the wellbore. Because the pressure on top of the mud column is atmospheric, a backpressure cannot be applied to counteract the effects of the equivalent circulating density (ECD), which is the difference in wellbore pressure when the pumps are on or off, and pressure fluctuations such as swabbing, surging and ballooning. This means that the HBS will be affected by considerable pressure fluctuations during drilling. 2. OBD drilling technique lacks the equipment and processes to manage a product that expands well over a hundred times when dissociating from GH form to free gas As overbalanced drilling has an open circulation system where mud returns to the surface and flows out of the well through piping open to atmospheric pressure, the well will have to be frequently shut in during drilling to circulate out gas in the well, which will result in large amounts of non-productive time (NPT). 3. Pressure in the wellbore is likely to be insufficient to prevent dissociation of GHs within the cased and open hole In addition, conventional methods might not be sufficient to resolve encountered well control situations. The conventional method of regaining control of a well by increasing the mud weight might not work if the well control situation originated because the GHs has been made unstable due to a too high temperature, not because the pressure is too low. Increasing the pressure in this case will not bring the GHs inside the P&T conditions where they are stable, and will therefore not slow or stop the dissociation. Increasing the mud weight might
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Shubham Satyam instead fracture the formation, causing fluid loss that decreases the hydrostatic pressure in the well, worsening the situation. 4. Fracture Pressure Consideration From a production point of view, drilling through the hydrate reservoir is likely to cause invasive formation damage, as the hydrostatic pressure at the bottom of the well in the annulus during OBD is higher than the formation pressure, meaning that mud and cuttings will flow into and damage the near wellbore area. This will have the possibility to significantly reduce the productivity of the hydrate reservoir, or even rendering it unable to produce at all (Todd et al., 2006). Due to the reasons mentioned in this section, the conclusion is that while drilling production wells through HBS is possible with OBD, it is far from being the optimal solution, and presents drilling problems that are difficult to overcome. B. Underbalanced Drilling Underbalanced drilling, or UBD, is a procedure used to drill hydrocarbon wells where the pressure in the wellbore is kept lower than the fluid pressure in the formation being drilled. As the well is being drilled, formation fluid flows into the wellbore and up to the surface. Use of Underbalanced Drilling may result in the following problems:
2. Uncontrollable Pressure in the Wellbore The limited amount of backpressure in typical UBD operations means that the pressure is not controlled throughout the wellbore until the inflow enters the production equipment, at least not to the point where the GHs are stable, which means that the GHs will expand fairly freely in the well. One major advantage when drilling through the hydrate reservoir with UBD is that there will be no invasive formation damage because there is no overpressure in the well, meaning that the drilling process will not cause a reduction in the reservoir`s production potential. Although this technique is much better at handling gas in the well and at the surface compared to OBD, the lack of control over the GH dissociation process in the formation and cuttings during UBD and the associated well control risks, in addition to the wellbore stability risks, leads to the conclusion that UBD is not the optimal drilling technique for drilling production wells in HBSs. C. Managed Pressure Drilling Managed Pressure Drilling is defined as an adaptive drilling process used to precisely control the annular pressure profile throughout the entire wellbore. The objectives are to ascertain the downhole pressure environment limits and to manage the annular hydraulic pressure profile accordingly.
1. Uncontrolled dissociation of Gas Hydrates
Advantages Of Managed Pressure Drilling:
Drilling into hydrate reservoirs with UBD, meaning that the formation fluids flow into the wellbore due to the lower pressure in the wellbore compared to the formation, has the risk of creating an out-of-control dissociation “chain reaction” and causing significant wellbore stability problems. The low wellbore pressure will cause GHs in the formation and cuttings to dissociate more rapidly than during OBD, and the gas volume entering the annulus and rising to the surface will significantly increase in volume, which will displace the mud and result in a reduction of the annulus pressure at the bottom of the well, leading to an increase in the dissociation rate.
1. Precise monitoring and control of the wellbore pressure MPD is an “adaptive drilling process,” where the drilling plan, operation and pressure profile in the well changes during drilling according to the conditions of the wellbore to precisely control the annular pressure profile throughout the entire wellbore. The objective is to monitor the limits of the downhole pressure environment and adjust the annular pressure profile appropriately, which is well suited from drilling through HBS, and especially well-suited for drilling through the hydrate reservoir.
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36 2. Gas influx in the mud is contained Contrary to UBD, which deliberately allows the influx of formation fluids into the wellbore, MPD will generally avoid flow into the wellbore, similarly to OBD. Any unexpected inflow that occurs during the drilling process will be safely contained using a suitable process (Todd et al., 2006). 3. Formation damage and unwanted fractures are avoided The very limited overpressure during MPD means that invasive formation damage in the reservoir is likely to be significantly reduced compared to OBD, and is not expected to significantly affect the production potential of the reservoir. 4. Gas Kicks, Lost Circulation and Differential Sticking is rare The common characteristic of the many different MPD tools and techniques that exist is that they were developed to limit well kicks, lost circulation and differential sticking, so that fewer casing strings would be needed to reach the total depth of the well. Although drilling with MPD has many advantages, those that are most relevant when drilling through
Drilling In Natural Gas Hydrate Reservoirs
hydrate formations is that it reduces problems when drilling through formations with a narrow margin between the formation pressure and the fracture pressure, which generally causes frequent losses of drilling mud and gains of formation fluids, and that it precisely controls the pressure of the entire wellbore during drilling, and is able to react quickly to changes in the wellbore pressure. Casing While Drilling Casing while drilling (CwD) involves using the well casing with a drill bit attached at the end of the drill string and rotating it from the surface to penetrate into the earthâ&#x20AC;&#x2122;s crust, in this way the well is both drilled and cased at the same time. The drill string is then cemented it in place in the well after reaching the target depth (TD). The drilling fluid is circulated down the inside of the casing and returns up the small annulus between the outer diameter (OD) of the casing and the formation. The large OD of the casing generally leads to considerably good hole cleaning due to the high annular fluid velocities in the small annulus, particularly at critical angles. Since the well is cased during drilling there is generally no tripping of the drill string. This serves to reduce many of the common drilling problems generally encountered during drilling.
Fig. 3 This is a proactive approach to drilling where problems are prevented before they occur instead of being dealt with afterwards. Non-retrievable CwD system and Retrievable CwD system are the two types of systems which exist.
Casing while Drilling advantages The overall Casing While Drilling advantages (CwD) lie in reducing the drilling and tripping times, mitigating the risk of drilling problems, and
Shubham Satyam
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consequently, decreasing the final cost of successfully delivered projects.
The points listed before can be arranged into:
The Casing While Drilling advantages listed are:
1. Borehole Stability This item is reached by the plastering or smear effect, which consists in that the proximity of the casing to the wellbore mixes the cuttings and drilling fluids into a consistency that mechanically alters and seals the annular ring; while the casing is plastering or smearing these cutting against the wall an impermeable barrier is created. This has been inferred because of the returned cuttings to the surface are finer and 10â&#x20AC;&#x201C;20 percent less than compared to a conventional casing set-up.
1. Improve borehole stability with less mechanical damage (wellbore integrity). 2. Reduce lost circulation. 3. Reduce trouble time. 4. Reduced number of casing/liner strings. 5. Improve Well Control and Personnel safety. 6. Drilling Time savings. 7. Improve hole conditioning and production. 8. Reduce rig requirements. 9. Enable more difficult wells.
From before, it reduces lost circulation problems and helps to prevent differential sticking.
Fig. 3 In over 300 field runs, not a single case of lost circulation has been reported outside of severely depleted zones where losses are inevitable. In the same 300 wells, the only case of stuck pipe was due to rig operation problems that resulted in the pipe remaining stationary without circulation for an extended period of time.
Problems associated with formations and wellbore conditions that deteriorate due to time exposed to drilling fluids are reduced simply because the exposure time is reduced. In addition, the inherent stiffness of the casing string in the wellbore produces a less tortuous hole,
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Scale Formation Promblems in Oil & Gas Industry...
providing a smoother wellbore and reducing the risk of key-seating and mechanical sticking. The stiff assembly is also less prone to vibrations, reducing the mechanical impact damage on the borehole wall. Drillstring vibrations have been attributed to borehole stability problems. Summarizing, it is positive against: ◀ ◀ ◀ ◀ ◀ ◀
Cave in Swelling Casing shoe takes more weight than anticipated Problems to rotate Problems to pull out (stuck) Problems of circulation
2. Equipment Involved It is quickly installed on any Top Drive system, electric or hydraulic, with typically no modifications to any existing drilling equipment. The Casing While Drilling provides a high level of mechanization, therefore eliminating the need for large and cumbersome travelling elevators; the high risk “stabber” position in derrick; the need for conventional Fill-Up and Circulation Tools; the need for and the hazards of conventional power tongs in a space-restricted area. TESCO CDS allows simultaneous rotation, reciprocation and circulation of the casing string enhancing capability to get casing to bottom through troublesome wellbores and gaining improved cementing results. Also: 1. It can be used for formations with as much as 18,000 psi compressive strength. 2. It eliminates Conventional casing operations which cannot rotate pipe. 3. It can eliminate conventional power tongs and equipment on drill floor. 4. No further interface to the rig or hook up of hydraulic hoses is required.
3. Personnel and Safety From point stated before, keeps personnel out of the line of fire; This reduces the number of personnel involved in the casing operations by two to four persons, reducing HSE exposure. As the tool is operated from the driller’s cabin, no personnel is required in the red operating zone. Also, the torque turn can be read wirelessly with the OWS Torque Turn sub and data can also be sent onshore to engineers if the rig has Internet connection and there is the option to send data from drill floor to this connection. Zero people in red zone. The safety issues are really big considerations in planning the project. In this case, the reduction in people involved actually raises the level of safety. Also, CwD helps in reducing the extra rig non-productive time (NPT). 4. Time Reduction Elimination of pipe tripping eliminates many of these problems. Running casing into a pre-drilled wellbore is sometimes problematic resulting in lost time “fighting” the casing string to bottom, setting the casing string off bottom, or tripping the casing string and making a wiper trip with a rotary assembly. With a “cement in place” system, there is nothing to remove from the hole and no requirements to place hardware in the casing prior to cementing. The float valve is in place during the drilling operations. Typical time savings are in the range of 30% of the time from section “spud” to LOT. Time for OWS TDCRTi (Casing While Drilling) is about 30 minutes, compared to up to up to 5 hours for conventional tools. Cementing Use of Low Exothermic Cement for Cementing the Casing:
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Shubham Satyam
The process where cement sets usually has the property of exothermicity, meaning that heat is released during an exothermic reaction, because heat is released from the hydration reactions of cement components. This heat release does not pose a problem in most areas; however, it becomes a significant problem in Arctic environments where permafrost and/or in environments where GHs are present. The heat that is released during the cement setting process can cause permafrost to thaw and GHs to become unstable and dissociate. Because the ice is the consolidation material in permafrost formations, the formation will transform from firm and stable to soft and unstable when the permafrost melts resulting in the formation of liquid water around the borehole. GHs that have been destabilized will begin to dissociate and release frozen or liquid water together with vast volumes of gas, thus increasing the pressure behind the casing. The situation in both these cases will threaten the integrity of the wellbore and the cement, and might damage significant sections of the wellbore. If gas is present during the hydration reaction of the cement, it could invade the cement and migrate through the pore structure along weak bonds, formation/cement interface or cement/casing interface, thus creating micro channels and/or an microannulus through which the gas can percolate while the cement sets and after the cement has set, reducing the integrity and strength of the cement. Schlumberger has come up with a solution for this problem by developing a new line of cements designed specifically for low-temperature applications, called the ARCTICSET cements and DeepCrete cement that are available for a variety of conditions. Articset: Although purposely designed for permafrost zones, this line of cement is also highly relevant to be used in formations containing GHs to limit or avoid dissociation during the hydration reaction of the cement since these cements have a low heat of
hydration and minimal heat release while setting. Other properties include: low free-water separation, low permeability, excellent resilience to temperature cycling and controllable pumping times and strength properties. Sufficient strength of the cement can be achieved in wells with temperatures down to –9°C. An additional improvement of the cement used to cement casings in HBS would be to include components in the cement that would prevent destabilization of the GHs. DeepCrete: The low water content of this system enhances the early gel and compressive strength development, while low densities minimize the risk of losses associated with the low fracture gradient encountered in many deepwater wells. These properties, combined with the DeepCRETE lower heat of hydration, help reduce WOC time, which is particularly important in areas where gas hydrates are a concern. Temperature Control Through The Wellbore During Drilling Monitoring and controlling the temperature in the wellbore during drilling in HBS relative to the stability areas of the GHs will be necessary to either avoid or severely reduce GH dissociation throughout the wellbore, which is very important to reduce hole stability issues and other drilling-related challenges. Keeping a low temperature in the circulating mud can be achieved by either cooling the mud, or minimizing heat transfer (insulation) to the mud from the warmer environment. Causes of Heating The effect achieved while drilling, consisting in heating the mud during circulation, is frictional heat, which generally originates from the following two main sources that accompany drilling operations: ◀ Viscous friction ◀ Mechanical friction
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Scale Formation Promblems in Oil & Gas Industry...
Solutions: 1. Surface Mud Cooling The temperature of the mud should be kept at a level that does not disturb the stability of the GH, which according to Hannegan (2005) means keeping the temperature within the closed circulation system below 11°C throughout the wellbore. To achieve this objective, surface mud cooling will have to play an important part. Surface mud cooling can be done in many different ways, for example the addition of blocks of ice in the mud or cooling the mud through a heat exchanger. In addition to stabilizing the GHs and reducing or eliminating GH dissociation, which is the most important advantage, mud cooling has the following additional advantages: 1. Increased borehole stability 2. Reduce the mud temperature while circulating and drilling and therefore helps maintain the rheological properties of the mud with lesser additives 3. Reduce bit temperature and wear on downhole tools that may be affected by high temperatures 4. Reduce the high mud return temperature, especially important for oil-based muds, which can thus be maintained below their flashpoint 5. Maintain the mud temperature below the design failure limits of BOP elastomers 6. Reduce the bottomhole circulating temperature allowing the use of measurement while drilling and logging while drilling tools to greater depths 2. Insulation – Equipment and Technology for Minimizing Heat Transfer One way of controlling the temperature of the mud without artificial cooling is through minimizing the heat transfer to the mud in the wellbore. This can be done by one of the following equipment and technologies: ◀ Marine riser (slim, insulated, dual flow, with surface BOP and/or pressurized, and booster line) ◀ Insulated dual flow drill pipe ◀ Casing insulation
A. Marine Riser (Slim, Insulated, Dual Flow, with Surface BOP and/or Pressurized, and Booster Line) The standard method in the oil and gas industry is to use risers to transport the fluids from the well to the rig in offshore fields. To achieve this in a controlled manner while drilling in HBS will be a difficult challenge since the riser is the environment where the pressure will be fairly low and the temperature will be fairly high, meaning that the GHs will be at its most unstable. As most of the riser is fully submerged in seawater, it will be at approximately the same temperature as the seawater. This means that heat will be transferred from the seawater through the riser and into the mud with suspended GHs, potentially leading to dissociation, assuming that the seawater is warmer than the fluid in the annulus. This heat transfer could be significant, especially in temperate waters. This heat transfer could be limited by using an insulated riser with a lower heat transfer coefficient, thus limiting the temperature increase, and therefore the dissociation and expansion of the GHs in the mud, but this is excessively expensive. Instead, the insulation could be achieved by a dual flow configuration with a cold fluid circulating in the riser annulus. A pressurized riser with a surface BOP would permit much higher pressure in the riser, meaning that the GHs would be stable at higher temperatures. A final option could be to use a slim riser, a riser with a smaller outside diameter than what is conventional, which will result in higher fluid velocities in the riser and therefore reduce the heat transfer to, and heating of, the mud. The booster lines on the riser are used to inject mud at the base of the riser, which is necessary to maintain the return fluid velocity in the riser at the same level as in the annulus of the wellbore, since the diameter of the riser is larger than that of the annulus in the wellbore. If the mud injected down the booster lines is cooled, this will increase the stability of the GHs suspended in the mud. According to Hannegan et al. (2004), maintaining a bottomhole temperature at 11°C is likely to prevent any GH dissociation in the wellbore and release of free gas in the riser.
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Shubham Satyam B. Insulated Dual Flow Drill pipe In situations where a riser is unpractical to use, one method to transport the returns to the surface from the wellhead could be through an insulated dual flow drill pipe. To reduce the heat transfer between the seawater and formation, each joint would be equipped with an insulated “covering” between the pin and box that had the same outside diameter as the pin and box. This drill pipe would have to be able to withstand the high pressures associated with GHs dissociating inside the pipe (Todd et al., 2006). According to Hannegan et al. (2004) this type of drill string is worth considering based on the heat transfer between the mud in the drill pipe and the mud return in the annulus during drilling with conventional drill pipe. The returns would be channelled into one half of the dual-flow drill pipe near the bottom hole assembly (BHA), while the mud and returns would be separated at the rig floor by a unique swivel mechanism. C. Casing Insulation Using an insulated outer casing would reduce the heat transfer between the formation and the well, thus reducing the temperature increase of the formation in sections where the temperature of the annulus is higher than that of the formation. This is especially important in limiting the heating of shallower hydrate formations when drilling deeper warmer zones, and during production, especially if the production method involves thermal injection, such as steam injection. 3. Circulation Rate A relatively high circulation rate will reduce the heat transfer between the mud and the formation and between the seawater and mud in the riser, thus reducing the temperature of the mud and leading to improved stability of the GHs. This advantage would have to be considered against the increased mud pump requirement and borehole stability problems due to increased annular flow and therefore borehole erosion. 4. Chemical Additives Using chemical additives (or avoiding dissociation-inducing inhibitors such as salts and alcohols) in
the drill mud helps to maintain gas hydrate stability in the formation and prevent gas hydrate dissociation in the drill cuttings. Conclusions The following conclusions were established on the basis of the earlier discussions in this paper: ◀ Dissociation of GHs in the wellbore must be avoided during drilling to reduce the consequences of well control problems and other drilling-related challenges. ◀ Dissociation of GHs in the wellbore can be limited or avoided by maintaining the wellbore temperature within the stability conditions of the GHs. ◀ MPD is the recommended optimal drilling technique based on its ability to precisely control the pressure of the entire wellbore during drilling and is able to react quickly to pressure changes by applying backpressure at the surface. ◀ The temperature in the wellbore can be controlled by surface mud cooling, insulation methods or changing the circulation rate. ◀ Surface mud cooling on its own can be used to lower the inlet temperature of specialized freeze-depressed muds down to between –3°C and 0°C, even when drilling surface and intermediate hole sections. ◀ CwD can be used along with MPD to reduce the probability and consequences of wellbore instability and other drilling-related challenges. ◀ Low exothermic cement should be used when cementing casings to prevent GH dissociation behind the casing. ◀ The optimal solution to drill production wells in hydrate formations is to combine MPD with CwD, surface mud cooling, insulation, thermodynamic inhibitors and kinetic inhibitors/anti-agglomerates, low exothermic cement during cementation and a relatively high circulation rate. The equipment, methods and drilling techniques discussed in this report are all existing and proven technology, and it is proposed that these and other existing technologies can be used together to drill production wells in GH reservoirs safely, effectively and economically.
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Scenario of CBM in India and Enhanced CBM recovery via C02-N2 Sequestration
References: [1] UNEP, 2014, Frozen Heat – A Global Outlook on Methane Gas Hydrates Vol 2. [2] Anders Gundersen, 2013, Evaluation of Methods for Drilling and Production of Hydrate Formations. [3]Erdem Catak, 2006, Hydrate Dissociation During Drilling Through In-Situ Hydrate Formations. [4] Prashant D Motghare, Amol Musale, Gas Hydrates: Drilling Challenges and Suitable Technology. [5] Moridis, G.J., 2011, Challenges, uncertainties and issues facing gas production from gas hydrate deposits. [6] Energies, 2012, Experimental Simulation of the Exploitation of Natural Gas Hydrate. [7] Milad Poorfaraj Ghajari, Hydrate-Related Drilling Hazards and Their Remedies. [8] Maribus Ggmbh, Energy From Burning Ice. [9] H. Vrielink, BP; J.S. Bradford, Chevron; L. Basarab, Tesco Corp; C.C. Ubaru, H. Christensen, 2008, Casing-while-drilling successfully applied in Canadian Arctic permafrost environment. [10] Schlumberger, 2006, DeepCrete- Low Temperature Cementing Solution
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Scenario of CBM in India and Enhanced CBM recovery via C02-N2 Sequestration Patel Karan, Sachin Nambiar, Nahid Shaikh
* University of Petroleum and Energy Studies Þ Dehradun The increasing price of natural gas and, in some cases, government policies have encouraged the exploration and development of gas from unconventional sources, which has led to the development of sophisticated technologies for enhancing hydrocarbon recoveries. The major objective of this paper is to study the effective, feasible, efficient methodology for the extraction of methane gas from coal seams, coupled with the injection of CO2 and N2 into the coal seam complex structure. This annexure focuses on how to improve exploitation rate of coal bed methane (CBM). There are currently two urgent major global issues the mankind is facing: one is the future supply of energy for an increasing (and increasingly energy-dependent) population. The other is the threat of catastrophic climate change as a resulof
global warming caused by greenhouse gases such as CO2. This paper seeks to address both issues by using CO2 Sequestration in the coal seams to produce the vast resources of natural gas locked up within the CBM. APPROACH of the paper ◀ Perspective of CBM in India : Energy dependence on CBM for natural gas demand ◀ Elements encompassing ECBM – As a potential for satisfying tomorrow’s high energy demand ◀ Factors leading/obstructing towards ECBM PURPOSE of the paper ◀ To understand the scenario of CBM in India ◀ How to enhance CBM production by sequestrating CO2-N2? ◀ Understanding technical and economic feasibility of ECBM Introduction to Coal Bed Methane Depletion of conventional resources, and increasing demand for clean energy, forces us to hunt for alternatives to conventional energy resources.
Patel Karan, Sachin Nambiar, Nahid Shaikh
CBM is considered to be one of the most viable alternatives to combat the situation. With growing energy demand, CBM is definitely a feasible alternative supplementary energy source. CBM is a generic term for the methane rich gas originating in coal-seams. It has potential as an abundant clean energy supply to help replace other diminishing hydrocarbon reserves. Recent developments in technologies and methodologies are playing a large part in harnessing this unconventional resource. The recovery rate of methane is usually limited by the coal seam gas pressure and diffusion rate and, as a result, not all available gas can be recovered. By injecting gas into the seam, further methane can be liberated. Enhanced CBM recovery is a method of producing additional coal-bed methane from a source rock, similar to enhanced oil recovery applied to oil fields. Carbon dioxide (CO2) injected into a bituminous coal bed would occupy pore spaces of the bed, pumping entrapped methane to migrate from the pore spaces, allowing for potential enhanced gas recovery and also helps in Carbon Capture and Storage (CCS) ideology, which is of major concern keeping the environmental aspects into consideration.
43 CBM has great potential of augmenting energy resources of the world and specifically India. Thus, enhanced CBM recovery and different methods of Carbon dioxide separation and storage will play crucial role in the future. Scenario of Coal Bed Methane in India Coal bed Methane (CBM), an unconventional source of natural gas is now considered as an alternative source for augmenting India’s energy resource. According to the data obtained from Directorate General of Hydrocarbon (DGH), India has the fifth largest proven coal reserves in the world and thus holds significant prospects for exploration and exploitation of CBM. The prognosticated CBM resources in the country are of about 92 TCF (2600 BCM) in 12 states of India. In order to harness CBM potential in the country, the Government of India formulated CBM policy in 1997 wherein CBM, being Natural Gas, is explored and exploited under the provisions of OIL Fields (Regulation & Development) Act 1948 (ORD Act 1948) and Petroleum & Natural Gas Rules 1959 (P&NG Rules 1959) administered by Ministry of Petroleum & Natural.
Fig. 1 Image credit: IEA Clean Coal Centre : “Potential for Enhanced coal bed methane recovery” by Dr L L SLoss
Under the CBM policy, till date, four rounds of CBM bidding rounds have been implemented by MOP&NG. It resulted in an award of 33 CBM blocks covering 16,613 sq.km out of the total available coal bearing areas for CBM exploration of 26,000 sq.km. To date, most CBM exploration
and production activities in India is pursued by domestic Indian companies. Total prognosticated CBM resource for awarded 33 CBM blocks, is of about 62.4 TCF (1767 BCM), of which, so far, 9.9 TCF (280.34 BCM) have been established as Gas in Place (GIP).(DGH India)
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Scenario of CBM in India and Enhanced CBM recovery via C02-N2 Sequestration
Current CBM production (March 2015) is around 0.77 MMSCMD from 5 CBM blocks, which includes test gas production from 4 CBM blocks and commercial production from 1 CBM block. Seven more CBM blocks are expected to start commercial production in near future. The total CBM production is expected to be around 4MMSCMD by end of the 12th plan as per XII plan document. As can be seen. India has great potential to cater the energy demand by the means of natural gas, i.e. CBM and much of the area is still not explored or in most of the area, despite blocks being awarded, the development of CBM field has not taken place. Seeing to this, the concept of Enhanced Coal Bed Methane Recovery could provide the means for more recovery of CBM to cater ever increasing demand for energy and also natural gas could be recovered in very short time (i.e. higher recovery rate) comparatively to normal coal bed methane extraction.
Theory and Concept of ECBM Adsorption is the main storage mechanism in coal seams at high pressure. Methane, which is one of the by-products (the others being water and CO2) of the coalification process in coal seams, is primarily stored as a sorbate on the internal surface area of the microporous coal. Injection of CO2 into deep seams initiates a displacement desorption process, thereby adsorbed methane is displaced by the injected CO2. The matrix of coal bed has immense capacity to store methane gas by the mechanism of adsorption. Thus, the free available gas (because of less fractures and cleat volume) is much more scarce than that adsorbed on the coal surface. Langmuir Desorption Isotherm helps to understand the pressure drop required to get optimum adsorbed gas volume. The Mechanism of CO2-ECBM operates on the basis
Fig. 2 Figure shows the relative absorption capacity of CH4, CO2 and N2 on coal samples of Wyodak â&#x20AC;&#x201C; Anderson Coal Seam(E. Robertson ,June 2010)
Fig. 3 Graph shows CH4 Production rate v/s time. It clearly presents an increased production rate and also the recovery is done in less time (i.e. all recoverable amount is extracted in less time than normal CBM).
Fig. 4 Not only production rate is increased but also amount, i.e, more of CH4 is recovered by ECBM.
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Patel Karan, Sachin Nambiar, Nahid Shaikh sorption capacity as CO2 has a better sorption capacity of coal (up to ten times greater, depending on coal rank) than methane under normal reservoir conditions. As CO2 is injected into a coal reservoir, it is preferentially adsorbed into coal matrix, displacing the exiting methane in that space. As a result, the methane diffuses into cleat systems, migrates to and produced from production wells. The mechanism of N2-ECBM is a bit different from CO2-ECBM and is quite costly, as nitrogen is injected into a coal reservoir, it lowers the partial pressure of methane, accelerating desorption, and recovers the methane gas. While C02-ECBM is more related to higher capacity of being absorbed on coal matrix than CH4. But pure CO2 or N2 by means of separation cause additional costs in the procedure so it has been found that the use of flue gas that is obtained from burning of coal or combustion of methane for energy production, i.e. consisting of CO2 and N2 (Percent of N2 is much lower as compared to CO2), could also serve the purpose of CO2 sequestration, Enhanced Recovery and that it is economically supportive, too. Production rate of CO2- N2-ECBM depends on the injection pressure, the efficiency of movement of the CBM from the adsorbed state in the coal matrix into the cleat or the fracture system of the coal, and the permeability of the cleats, the pathway to the wellbore. Following are the two graphs showing effectiveness of ECBM in terms of CH4 recovery and also in terms of production per day. Technical and Economical Aspects Following are the aspects that are needed in order to establish a plant for enhanced CBM recovery or the factors that might hinder its development. Geological/ Technical Aspects: 1. Homogeneity 2. Simple structure 3. Permeability >1 md 4. Depth 300â&#x20AC;&#x201C;1,500 meters 5. Concentrated coal geometry
6. Production rates 7. Development timing 8. Water disposal 9. Amount of available gas Economic Aspects: 1. Cost of CO2 2. Cost of N2 3. Availability of injectant gas 4. Value of methane 5. Cost of processing 6. Cost of implementation 7. Transportation Policy/ Legislations: 1. Tax or CO2 Credits 2. Mine safety regulations Data from the unmineable Wyodak-Anderson coal zone shows that without injection, the project would take around 26 years to recover almost 72% of the CH4 in place. The flue gas injection scenario would recover 70% of the gas in place within 17 years and would result in 133,358 Gt of CO2 storage. The CO2 injection approach would succeed in storing significantly more CO2 (6,223,292 Gt) and would produce more CH4 (88%) within 19 years. Although this may suggest that the flue gas injection approach is the most economic, the amount of CO2 stored is actually relatively small â&#x20AC;&#x201C; the project is more of a success in terms of enhanced CH4 recovery than CO2 storage. Conversely, the CO2 injection option can be seen as a true CO2 storage option but would not be economically viable without forced or voluntary subsidies. Thus, the value of carbon credits into the future will be a major economic factor to define the viability of ECBM processes and projects. International tradeable credits should facilitate this process. Currently it would seem that only China is continuing with work to develop ECBM potential. The growing population and energy demand coupled with the desire to move away from coal, makes ECBM more attractive in China than it may be
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Scenario of CBM in India and Enhanced CBM recovery via C02-N2 Sequestration
elsewhere. However, even if the Chinese are successful in demonstrating a project at commercial scale, the nature and economics of ECBM is so site specific that success will be achieved only on a case by case basis.
India is next to China in terms of population and also is major contributor in terms of CO2 production so considering the scenario, India should strive forward to accept and develop this technology (ECBM) if it is geologically favourable.
Results from research held in 29 possible ECBM sites in China have determined that CO2 sequestration potential is of about 143 Gt in the country’s known coal beds. This could sequester CO2 emissions for estimated 50 years based on China’s CO2 emission levels in 2000. From the successful commercial projects China has forecasted to reduce the temperature of China by 2–3 0C by 2030 by reducing the CO2 level along with current rate of ever increasing CO2 emission.
Idealized conditions for ECBM Keeping the above conditions in consideration, the most important factor is the depth of the coal seam. Considering this parameter as major, following is the list of Indian Blocks where ECBM could be put into practice or the validation of practicality of ECBM could be possibly done on the basis of economics. The above table is in reference with the present CBM fields in India which could be
COAL FIELD ideal for ECBM in INDIA
DEPTH OF COAL SEAM
Parbatpur Central Mine, Bokaro, Jharkhand (high
>1500 feet
Tab. 1
volatile bituminous Gondwana coal) Godavari Valley Coalfield (low rank Gondwana coals)
2000 feet
North Karanpura, Jharia CBM block, Jharkhand (high
> 2000 feet
volatile bituminous Gondwana coal) Barakar and Raniganj, West Bengal
400 m to 1500 m
(Permo-Carboniferous Bituminous coal)
potential ECBM site, taking into consideration onlythe basis of its depth. (Optimal depth range for ECBM is considered to be of approximately 300–1500 m. Source: IEA Greenhouse gas R&D Programme, Report 1999). Many other parameters like gas content, rank and grade of coal, permeability, cleat spacing etc. are required to be analysed in depth for the development of an ECBM project. Conclusion It is important to note that the primary aim of both CBM and ECBM projects is economic profit through CH4 recovery. The use and potential capture of flue gas or CO2 in ECBM is currently not a source of economic advantage in any way and is unlikely to
become such without a reduction in gas processing costs as well as tax incentives or carbon credits. For an ECBM project to be economically viable, several factors must be optimised: ◀ The gas to be injected must be low cost and readily available; ◀ The CH4 produced must be profitable; ◀ The processing of injected gases must be affordable; ◀ Any additional site costs must be low; ◀ Additional gas and equipment transportation costs must be covered. ◀ The value of carbon credits into the future will be a major economic factor to define the viability of ECBM
Patel Karan, Sachin Nambiar, Nahid Shaikh
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References: [1] DGH India [2] P. Massarotto, V. Rudolph, Suzanne D Golding ( University of Queensland ) ;Technical and economic factors in applying the enhanced coalbed methane recovery process; conference paper, 2005. [3] Development of Indian CBM Resources – Challenges and Issues by N. K. Punjrath, GM – Block Manager CBM Asset, ONGC, Bokaro Steel City. [4] IEA Clean Coal Centre : “Potential for Enhanced coal bed methane recovery” by Dr L L SLoss, May 2015. [5] Global CCS (Carbon Capture and Storage) Institute; Publicaton : Technology: Enhanced Coal Bed Methane (ECBM). [6] Wikipedia : Enhanced Coal bed Methane Recovery. [7] Report No. PH3/3, August 1999 : IEA Greenhouse Gas R&D Programme.
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How it Works? Agitator™ – NOV solutions
How it Works? Agitator™ – NOV solutions Filip Czerniawski
Drilling is an extremely complex process that requires constant improving. Specialists from NOV came out with a unique idea to reduce friction of the drill string against the wellbore using the Agitator System. Friction is an essential force present in our life, but there are some processes in which we need to reduce it as much as possible. The Agitator reduces friction and improves weight transfer by creating axial oscillations in the drill string. The results are very satisfactory. According to the paper „Drilling Performance Improvements in Gas Shale Plays using a Novel Drilling Agitator Device” new device gives much innovation to the process of drilling. Improved weight transfer to the bit enhances the performance in several ways, including; ◀ PDC bit life can be extended because of constant and improved weight transfer. Several post-run bit characteristics have shown that no damage to the bit occurred because of impact forces ◀ Lower WOB will be required ◀ Reduction in drill pipe compression as weight is transferred effectively avoiding excessive fatigue and excessive side force ◀ Improved Tool Face control ◀ Improved ROP ◀ Improved tortuosity through more controlled DLS For better visualization of the problem let’s focus on static friction. When we put our phone on slope, it stays in the same position. That means that the motion is lower than the friction force. Let’s assume now that the phone starts ringing and vibrating. Suddenly phone begins to slide. This change in po-
sition tells us that the oscillations from the phone help break static friction. In the link below, we can see the short footage about this problem. < http://www.nov.com/Segments/Wellbore_Technologies/Downhole/Agitator_Systems/ Agitator_System/Agitator_System.aspx > Stick-slip is an irregular drill string rotation. Causing the string to periodically torque up and then spin free with above average RPM causing severe damage to the bit and BHA. Reducing the stick-slip helps in keeping the bit for longer period of time and increases ROP. Vibrations from Agitator System also aim to reduce the friction. What’s more, the low magnitude oscillations only affect the longitudinal axis of the drill string. The Agitator system counts three mechanisms: ◀ The power station drives the valve section, producing pressure pulses in the system. These pulses activate the shock tool or act on the coiled tubing, creating axial motion, which breaks static friction. ◀ The unique valve system is the heart of the tool, converting the energy from the pumped fluid into constant pressure fluctuations. The cyclical restrictions are made through the pair of valve plates. The flow area changes create constant pressure pulses that are proportional to the flow rate. ◀ A shock tool is necessary to create the axial oscillation of the string to reduce friction. Once the internal pressure is applied to the pump area, the mandrel extends. When the pressure decreases the mandrel returns to its previous place. The best place for the shock tool is directly above the Agitator.
Filip Czerniawski
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To sum up, the idea of the Agitator is based on lowering static friction. That implies better weight transfer to the bit, improves ROP and tool face control, increases bit life and much more.
It is important to keep in mind the right placement of the tool. Only then, we can ensure maximum effectiveness.
Agitator relies on three main mechanisms: Power section that drives the valve section producing pressure pulses. The excitation section converts the increase in pressure into axial movement that breaks the static friction.
An improvement in ROP and other aspects have also economic impact. The use of Agitator is giving opportunities for major boost in the process of drilling.
References: [1] “Drilling Performance Improvements in Gas Shale Plays using a Novel Drilling Agitator Device”; <https://www. onepetro.org/conference-paper/SPE-144416-MS>. [2] Agitator system handbook; <http://www.nov.com/agitator/img/2-Agitator-Handbook.pdf>. [3] <http://www.nov.com/agitator/>. [4] “MWD Failure Rates Due to Drilling Dynamics”; <https://www.onepetro.org/conference-paper/SPE-127413-MS>. [5] <http://www.nov.com/agitator/img/222.pdf>.
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