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Martin Findlay, KPMG, UK, reviews the current state of the oil and gas sector operating across the UKCS, and discusses the industry’s journey towards net zero.
he oil and gas industry has recently contended with a series of extremes. After a run of years absorbing heavy financial losses, the pandemic caused demand for oil and gas to effectively dry up. Then, the global COP26 summit in November 2021 put further pressure on the industry to accelerate plans for transitioning to a greener future.
At the start of this year, rising gas prices were exacerbated by the war in Ukraine, and were driven by a combination of strong demand from China, as well as Western oil majors cutting back on exploration and production.
The Energy Transition Survey, one of the Aberdeen and Grampian Chamber of Commerce’s flagship pieces of research, which KPMG UK sponsors, has followed Scotland’s energy sector through these ups and downs, but never has so much changed so quickly in such a short space of time.
The survey, which launched its latest findings in May 2022, says that for now the good times may be back, but there are some important caveats to be aware of to get the full picture of where the industry operating in the North Sea currently sits.
The research shows that the value of international work is rising across all sectors, and confidence has rebounded, with 84% of energy firms believing their revenues will grow in 2023. There are positive indicators for the transition as well. Concern about the return on investment from renewables is falling, which bodes well for the future, and companies here now believe that almost half of their operations will be outside of oil and gas by 2030.
The skills gap remains a big issue
A big concern of companies operating in the North Sea is access to skills and labour one of the most important pieces in the energy transition puzzle. There is so much about the energy sector that is different to other parts of the economy, but when it comes to human capital, the sector faces similar headwinds to almost every other business in the world right now – the skills and talent needed to move us towards a greener future are in sharp demand.
The firms surveyed by KPMG are clearly concerned about how to attract new people from outside the industry to work in oil and gas. The firms who can demonstrate their willingness to embrace the energy transition and their desire to flourish in the economy of the future will find that retaining and attracting talent will not be as challenging.
Workers are as precious a commodity as the energy they produce Skilled workers have again become almost as precious a commodity as the energy they produce. KMPG’s latest research suggests this problem is only going to become more acute. There has been a 16-percentage point increase in the loss of staff to other oil and gas basins globally, suggesting that the battle for workers has become an international one.
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At the same time, seven out of ten firms say they will need to grow their headcount over the next three years to cope with an increase in work. Something must give. Following the decline in production seen in the UK Continental Shelf (UKCS) over the last decade, it seems odd to be talking about labour shortages. But the data clearly points in this direction and history tells us that this has potential to inflate wages and put pressure on costs. In the case of oil and gas, this is bad news in what is already a mature and expensive basin.
Careful planning and investment at a corporate and government level are needed to make sure Scotland’s decades of experience, the current skill sets, and existing infrastructure are used to their full potential as we move towards a greener future. Doing so will allow key cities such as Aberdeen to prosper as a major player on the global energy stage and continue its long tradition as a powerhouse for the local and UK economies.
Change is afoot
Clearly the perennial issue of climate change is not going away, and change must continue to happen. The industry is leading on that, and understands that it has the potential to grow Scotland’s economy and be a driving force in facilitating the transition to a lower-carbon economy and a net zero future.
The direction of travel is clear amongst oil and gas firms. They are expecting their businesses to transform substantially and at pace across the next decade. The firms KMPG surveyed predict that, on average, the share of their business outside of oil and gas will jump to 50% by 2030. With growing demand to support North Sea offshore wind development via leasing rounds, as well as traditional decommissioning projects, the work will continue to grow and vary.
The clock is ticking
Despite the clear need for companies to transition faster, the survey shows that more than a third of companies have yet to develop a net zero strategy.
Most across the sector are diversifying outside of oil and gas in some shape or form, although one in five still have no plan to change. Most pure play oil and gas exploration and production companies are addressing their own carbon footprint. But for those without a blueprint for transition, and where external stakeholders are increasingly looking for substantive transition plans, the clock is ticking.
Individually firms must ensure they remain focused on the long-term objective. This will allow firms to succeed, workforces to grow, the economy to benefit, and the planet to thrive.
What companies do now across the three strands of environmental, social and governance (ESG) will determine the talent they attract, the customers they serve, the profits they make, and ultimately the impact they will have on society.
What comes next?
Given the very real consequences of global warming, it is clear we must inject pace and clarity into the energy transition. It has become increasingly obvious that there is a need for clearer regulatory alignment between the UK and Scottish governments. Only 28% of firms surveyed believe support for an energy transition is visible, and this lack of clarity needs to be tackled urgently.
Delivery of offshore wind, for example, is a long and complex process. However, we must do all we can to speed this up. ScotWind an auction of seabed plots for major offshore wind
projects around the Scottish coast which netted £700 million earlier this year will be crucial to Scotland’s net zero targets. Consideration should be given to a new offshore wind directorate to speed up delivery of this and other offshore renewables projects, given the complexity around sequencing, supply chains, and the number of stakeholders involved.
The ScotWind leasing auction attracted more than 70 bids from major oil companies, utility firms and investment funds from around the world. Most of the sites are on the east, north east or northern coast, with just one on the western side of Scotland.
Successful bidders include Scottish Power, which won the seabed rights to develop three new offshore wind farms with a total capacity of 7 GW. The farms include two new floating projects in conjunction with Shell and one fixed project.
The seventeen successful projects cover a total of 7000 km. 2 They have a combined potential generating capacity of 25 GW well above the expected auction outcome of 10 GW.
Scotland has 1.9 GW of operational offshore wind, and another 8.4 GW in construction or advanced development. While these leasing rounds are welcomed, it will be some time before these come online.
Windfall tax
Meanwhile, in the UK, a new windfall tax was introduced earlier this year, described as a 25% Energy Profits Levy. It applies to profits made by companies from extracting UK oil and gas and the Treasury expects it to raise about £5 billion in its first year.
When the Energy Profits Levy was announced in May of this year, it included an Investment Allowance which made energy companies eligible for tax savings worth 91p in every £1 on investments in fossil fuel extraction in the UK. Even though only temporary, the new levy means UK energy companies, which have been taxed higher than any other sector since the 1970s, now face a larger tax burden.
When tax on energy companies was last increased under previous chancellorship, the appetite to invest in the UK energy sector reduced. The UK Government will not want to see the same thing happen again, at a time when energy security and funding the energy transition are front and centre of the political agenda –hence the inclusion of an 80% investment allowance in the levy.
Many in the oil and gas industry feel strongly that this latest tax could make the North Sea – already one of the world’s most mature basins less attractive to some investors and possibly put recruitment at risk.
Various players across the industry are calling for politicians to take a pragmatic view and be wary of the impact that short-term tax policies and continuing doubts over the future of exploration and drilling will have on investment and confidence in a sector that is of critical importance to our economy.
A bright future ahead as transition feels certain
The oil and gas industry is in a strong position overall. Producers and companies throughout the supply chain remain committed to the transition but individually they must remain focused on the long-term objective. That is the only way firms will succeed, workforces will grow, and the planet will thrive.
Keeping both eyes firmly on the future will allow those operating across the UKCS to prosper as major players on the global energy stage and continue the region’s long tradition as a powerhouse for the local, UK, and European economies. The test that firms are facing now is how firmly to keep the pedal pressed to the floor on the journey to net-zero.
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Bhavesh Ranka and John Hatteberg, Cudd Well Control, USA, describe the advantages of automated cloud-based audit programs over more traditional manual methods of wellhead inspection.
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The oil and gas inspection industry operates according to stringent standards that strive to keep equipment running efficiently while maintaining workplace safety. Oil and gas companies demand a low failure rate to stay profitable. Their assets, however, are subject to heavy use and are constantly exposed to the elements. Therefore, one of the most important steps a well owner can take is to visually check the wellhead and the surrounding area to detect potential issues before they become problems. Typically, trained technicians conduct these wellhead inspections to detect welding flaws, corrosion development, and cracks. However, previously they have had to rely on spreadsheets to note any findings, then write a report, and send it to the operator. This approach has proven to be time-consuming and can easily lead to human errors, both of which can negatively impact operations.
To help address this challenge and aid operators in increasing the efficiency, traceability, and accuracy of their wellhead audits, Cudd Well Control has launched a fully automated wellhead audit tool that can help save operators time and money. The new wellhead audit platform is an efficient tool that allows operators to inspect the surface of a wellhead faster than traditional pen and paper methods while helping to identify any problems with corrosion, valve functionality and pressure. As a cloud-based solution, the tool can provide customers with advantages when conducting wellhead audits.
Streamlined software
The wellhead audit tool is a streamlined system that enables users to inspect and write wellhead audit reports in under an
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hour as opposed to what used to take several days to complete. Engineers can conduct these audits onsite with an iPad or tablet, enter the data, and the program will create customised,
immediate reports. For customers with wells in remote locations, the platform allows them to complete more audits in a day and access that information immediately.
Since the size and scope of each operator’s assets can vary, the platform was created to be flexible in order to meet customer needs based on their data/well count. Inspectors see the well condition immediately on one platform instead of having to go to multiple resources or sources. This new solution is based on API standards with all findings uploaded and shown on a customer’s wellhead audit dashboard that is accessible 24 hours a day. As security of information is always a critical issue, the platform features a private and secure portal where users access the information via a login name and password protected interface. The site administrator can add or delete user access as needed.
Digital solutions: a new chapter for the oilfield
With the industry adopting more digital solutions, wellhead audit tools are the next step at the oilfield. Customers can go online via a private portal and review all the data, results, maps, recommendations, print reports and more. Currently, this is done by hand and with an excel spreadsheet. Using the platform, users can pull up every inspected well in their region and see the visual inspection data and status. The interface graphically displays what is nearby the wells, such as schools, residences, pipelines or rivers – anything that needs to be considered when taking steps to conduct remedial activities on the well. Users are provided with a map view of the wells, which are identified with their status coloured coded in green for ‘all good,’ yellow for ‘caution,’ and red for ‘requires immediate attention.’
Users of the platform can also look at the history of the wells and see how they have been treated over time. This advantage also extends to companies considering buying a well or a series of wells, as it confirms what condition the wells are actually in. The tool features pop up details of the wellhead including its overall condition and details on any potential issues or problems that need to be addressed, such as corrosion or a valve not functioning. To provide comprehensive information, the software provides historic data from previous audits. These findings are further supported by photos as well as comments from the auditor. When the audit report is completed, an email is sent to the customer with a link to the portal.
Identifying which wells to address first
Operators must constantly work according to budgets and schedules. With this tool, problem wells go to the top of the risk matrix, allowing operators to deduce which wells to take care of first, so they can keep production flowing. The condition of the wellhead dictates what takes priority – repairs or remedial work. As a result, operators can quickly
16 | Oilfield Technology Autumn 2022
Figure 2. Map view of wells and API number on the right hand table.
Figure 1. Wellhead images taken during an audit and a schematic drawing to the right, displaying that all components of the wellhead have passed the audit and are in good condition.
Figure
3.
A closer view of the map with the well icon defining the well type, such as production or storage.
take preventative measures to avoid further issues and possible catastrophic events, preventing injuries whilst also saving time and money.
Assurance for the insurance industry
Older wells represent the biggest liability insurance companies can face when underwriting wells. Often, these companies do not have the accurate information needed to make the decision on which wells to underwrite and which wells to pass by. To address this, the wellhead audit tool has access to the API 10 numbers database. So, if an underwriter has wells to underwrite, they input the wells’ 10 API numbers and the tool goes to that database to see the age of the wells, how deep they are, the types of wellheads used, the well types, and much more. With this vital information, insurance providers can make the right decision on which wells to underwrite.
Asset protection
Figure 4. Problem wells go to the top of the risk matrix, allowing operators to know which wells to focus on first.
Oil and gas wellheads provide the structural and pressure-containing interface for drilling and production equipment. Ensuring all equipment at the wellhead is in working order is key to remaining online and productive. When wellhead equipment fails, the cost can be incredibly high both from an environmental perspective and from the time and expense it takes to remediate any failure. For those reasons, operators need to be consistently proactive about conducting wellhead inspections.
Wellhead audit tools help operators ensure that assets, equipment, and related componentry at the wellhead remain free of defects and damage. Users benefit from a combination of software development expertise and asset protection. Whether operating 10 wells, 100 wells, or more, this automated solution allows operators to inspect larger quantities of wells faster and more accurately, so they can strengthen their well control barriers, avoid incidents, and enjoy safer and more reliable operations.
Keep up to date with us to hear the latest in upstream oil and gas news Stay informed www.oilfieldtechnology.com
n upstream process plant collects production data from many different wells, sometimes hundreds. A general concern among oil and gas field operators is reducing their oilfield factors. This is the percentage between the production of the surface facility and the actual reporting from wells. It is not only because oil and gas are limited resources, but they are also crucial for financial and technical reasons. Wells do not always behave as operators expect. It is important to close the systematic gap between actual and planned production. Yet, no technology is available that completely solves this problem which causes companies to lose money.
Once a day, operators usually close the balance and compute the production of each oilfield facility. In the process, they estimate the flow that each well, reporting to that facility, has contributed. The proportion between the production of the surface facility and the wells reporting to it is the ‘oilfield factor.’ In oilfields with low levels of instrumentation, well measurement methods, and control
Gustavo Cerezo, Yokogawa, and Federico Neira & Lucas Nieto, KBC (A Yokogawa Company), Argentina, describe an approach for precise well measurement in order to reduce losses and meet production goals.
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mechanisms, the factor may vary between 0.75 and 0.9. Most of the variations are due to ‘non-localised losses,’ where operators have yet to locate the reason for the loss.
A combination of Yokogawa hardware and KBC software was tested at a major Argentine upstream facility to provide an approach for operators to frequently and precisely measure wells reducing non-localised losses. This solution identifies the
wells that are bad or good actors in a timely manner so operators can act accordingly. The result is that they are able to meet production goals and save money.
The proper operation of an upstream oilfield for accounting and planning purposes includes a systematic activity called ‘well testing.’ A well test is simply a period during which the production of a well is measured, either at the well head with portable well testing equipment, or in a separation facility. Nowadays, well-test measurement mechanisms are complex, expensive, and sometimes inaccurate. This procedure is executed with tanks or separators (two-phase or three-phase, depending on the wells’ characteristics).
Well testing is associated with two key challenges:
Ì High CAPEX: the number of wells far exceeds the available testing facilities.
Ì High OPEX: a well test is expensive and time-consuming so assessing a well may only occur once every several weeks or months.
Therefore, well testing needs to follow a set schedule but results in the following issues:
Ì Daily production estimates are based on flawed information.
Ì Testing schedules are determined with imperfect information.
Ì Downtime estimates are unreliable.
Ì ‘Non-localised’ losses can go undetected.
In 2019, Yokogawa and a major Argentine upstream operator agreed to conduct a pilot project using existing hardware and software technology to allow, through a real-time solution, improvement in procedures associated with production allocation, downtimes estimation, well testing assistance, and non-localised losses estimation.
To complete the proof of concept (POC), the operator made available a battery with 10 wells located at a major oilfield in a western province of Argentina as shown in Figure 1. The solution was developed using two technologies; firstly KBC’s Visual MESA® -Production Accounting (VM-PA), and secondly Yokogawa’s ROTAMASS TI – a Coriolis type meter (Figure 2) which excels in measuring multiphase flows very accurately even with large quantities of gas present.
The solution aimed to achieve the following objectives:
Make production data available to corporate accounting systems in near real-time.
Allow operators to quickly identify inefficient ‘bad actor’ wells, detect differences, and respond accordingly.
Improve the well testing process in terms of frequency and scheduling to reduce CAPEX and OPEX.
Calculate downtimes more accurately.
During the following years, information was collected to build the solution while the operator installed three Rotamass meters in certain lines. These lines were chosen based on their position to achieve the expected results of the pilot, as shown in Figure 3.
The solution
The solution ran autonomously and allowed manual interaction. Data was collected and stored in the local historian. Then, the algorithm evaluated the data in
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Ì
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Figure 1.
Oilfield study location.
Figure 2.
Rotamass meters installed.
near real-time and generated results such as oilfield factor, downtimes per well, adjusted production per well, deviations, and bad actor wells. Results appeared through dashboards, data tables, and reports in the system’s web interfaces as depicted in Figure 4.
The solution produced the following main outputs: daily production closure (Figure 4), an ordered list of wells to be measured at high frequency through the Rotamass meter on the test line, and an ordered list of wells for conventional testing (Figure 5). As a result, the solution achieved higher quality and more timely data available for more efficient accounting and planning. Using these ordered lists as a guide, the operator can now guarantee the quality of the data through a prioritised well test schedule.
The following factors have been agreed upon as key success indicators (KSI) of the solution.
Identifying bad actor wells that affect the plant
On a near real-time basis, the system generates two lists of bad actor wells, which should be sent for high frequency testing through Rotamass control, and conventional control through a three-phase separator. In normal operation, the system sends wells to Rotamass for high frequency testing according to this ordered list. When the system detects an abnormal state, the second list should be considered to help prioritise the schedule and reduce the frequency of conventional controls. As the system successfully maintains an ordered list of suspicious wells, the KSI is achieved.
Reducing production deviation below 10%
By using the solution alone, a more accurate calculation of the oilfield factor was possible. It is possible to further reduce this deviation by frequently controlling the wells using Rotamass as per the solution’s recommended ordered list and feeding the data back into the system.
Measuring liquids despite significant presence of gas
The Rotamass meters operate normally, even though 40% of the volume is gas.
The solution is prepared for estimating downtimes in at least three different ways depending on the available information and the oilfield’s automation level. The selected oilfield ran the three methods simultaneously for comparison.
Conclusions
The implemented solution allows for near real-time calculation of well downtimes in at least three ways, depending on data availability and technical conditions of different batteries. Despite the presence of gas, the implemented solution can calculate production values and allocate the production of individual wells. Detecting bad actors quickly and remediating them reduces their losses and impact.
Since various downtime estimation methods successfully underwent testing, this same system can connect to other, less automated collectors. CAPEX costs can decrease as the demand for two-phase and three-phase separators decreases, allowing each to serve more wells, while operating the conventional control less often reduces OPEX. More accurate daily accounting for planning and finance improves decisions about well operations and reduces losses due to missing production. A preliminary study is useful for other less automated batteries with no operating status information, as the average logarithmic temperature difference has demonstrated satisfactory accuracy as an empirical factor for the application of the downtime algorithm.
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Figure 4. Daily production closure dashboard.
Figure 5. Main operational outputs dashboard.
Figure 3. Representation of the selected battery.
anaged pressure drilling (MPD) and wired drill pipe (WPD) can significantly improve the identification and management of downhole events while augmenting surface automation and wellbore visualisation.
While MPD has been recognised for some time, the industry has since undergone changes both commercially and technologically. Initially offered as a third-party service, MPD has started to shift towards an integrated service offering of the rig contractor. One of the more significant technological improvements is the embedding of hydraulic models to automatically operate the MPD choke, removing humans from the control loop. Although MPD has become more sophisticated with time, there is still more value that can be derived from its use.
MPD and WDP improving MPD workflows
Fingerprinting is an essential task performed before the start of an MPD section. Online hydraulic models are calibrated against measured downhole conditions to mitigate the compounding effects of instrument resolution error and rounding errors. In more conventional approaches, as shown in Figure 1, the crew inputs configuration data and live instrumentation data into the hydraulic model. The crew then corrects the model to match the measured pressure from the pressure-while-drilling (PWD) system data. This process can take anywhere from several hours to more than a day. Over time, the cost of fingerprinting the well before an MPD section can be significant.
NOV is working to solve this problem by incorporating WDP into an optimised MPD workflow, enabling high-speed electronic downhole telemetry data to calibrate the hydraulic model (Figure 2). Incorporating WDP data into the model calibration sequence allows the system to capture and transmit data faster, particularly during low or zero flow steps where conventional PWD telemetry systems stop transmission. This approach enables the rig to spend less time in low or zero flow states to capture and transmit data to the surface. Notably, although the online model accounts for downhole conditions, the model is based entirely at the surface, and once calibrated, relies exclusively on surface-acquired data.
WDP availability also enables new operating modes to supplement contemporary MPD workflows. Electronic telemetry of WDP downhole tools provides a reliable signal
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Jessica Stump and Austin Johnson, NOV, USA, discuss how optimised workflows can help improve choke control and downhole event detection and consider how the MPD-WDP combination is boosting the industry’s move towards autonomous drilling.
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through the pump ramp transient period. This means that MPD connections may be simplified using a high-speed sampling of WDP downhole tools with measured downhole pressure feeding the choke controller directly, adjusting for time delays and depth offsets (Figure 3). Downhole pressure may be extrapolated from a single measurement and corrected with the assistance of the hydraulic model. This feature enables the choke to control directly from a sensor at or near the zone of concern rather than a sensor located up to five miles away.
WDP enabling downhole event detection
Coupling online hydraulic modelling with WDP presents significant advantages through downhole event detection in operations with MPD and WDP or in WDP standalone operations. One of the major drawbacks of contemporary event detection technology is that the data flowing into an algorithm is surface-acquired or single-point time delayed low-frequency data. Any alarms or automated functions are triggered with very limited direct knowledge of downhole conditions. While estimated hydraulic
model data closely matches measured downhole data under normal conditions, actual downhole conditions may not match the model during contingency events.
Surface-based models may not match real downhole conditions during an influx if the gas enters the solution. A contemporary kick detection system will detect the influx when the flow out the well exceeds the flow coming in. In the solution gas case, however, the gas volume may not displace significant volumes of drilling fluid from the well, limiting the effectiveness of conventional kick detection systems. The entry of the solution of gas into the mud may continue undetected for several minutes until the gas saturates the mud and displaces it or the gas in the mud reaches the bubble point pressure.
Surface-based models may also not match real downhole conditions during a wellbore stability event. In a wellbore stability event, insufficient wellbore pressure may cause compressive failure of the wellbore to occur. Material from the borehole wall collapses into the well and is circulated out with the cuttings. The collapsed material has the same effect on average fluid density as cuttings do, leading to a cuttings load that is higher than modelled. The model only accounts for drilled cuttings; no such corrections are applied for collapsed material, and no surface change is immediately seen after a partial collapse. Kick detection systems are not designed to detect wellbore stability events; the value of a flow-out flow-in comparison is diminished because the volume of the collapsed material matches the void left by the collapsed material. Mass balance tools such as a Coriolis return flow meter are ineffective because the collapsed material is located downhole and is not detected until it is circulated to the surface.
Curiously, wellbore stability events can occur undetected in self-perpetuating cycles. Low wellbore pressure, the root cause of many wellbore stability problems, results in mixing collapsed
Figure 1. Conventional MPD workflow. Download technical white papers for free from companies across the upstream industry Review new trends and technologies www.oilfieldtechnology.com/whitepapers/
material with cuttings, increasing the average fluid density. The increased average fluid density temporarily mitigates the cause of the wellbore stability problem. Eventually, the collapsed material is circulated out of the well undetected, and the initial condition leading to the wellbore stability problem returns; the cycle repeats undetected while wellbore quality deteriorates.
Both in kick events and wellbore stability events, even the most accurate drilling models using surface-acquired data may not truly reflect downhole conditions.
Combining WDP with MPD in a downhole event detection system significantly improves the rig crew’s visibility of subsurface events. As with contemporary systems, an online hydraulic model estimates drilling variables along the drillstring using surface-acquired data. The WDP enables the system to take measurements of the actual drilling variables along the drillstring. The downhole WDP measurements represent the downhole conditions as they are, whereas the estimates from the hydraulic model represent the downhole conditions as the rig control system can observe. This allows the downhole event detection system to directly compare measured values to expected values; a mismatch indicates an unexpected event or deteriorating downhole conditions, as shown in Figure 4.
In the solution gas kick case, the downhole event detection system may compare measured vs expected temperature along the string for early indications of a kick. Gas mixing heats or cools the drilling mud in unexpected ways. Comparing the measurement to the model allows the system to take along-string drilling fluid temperature deviation as an indication of a kick. This deviation may occur before solution gas reaches the bubble point, allowing the rig crew to act before a contemporary kick detection system sees a flow change. Notably, kick size is determined by inflow rate and event duration; by responding to a kick earlier, the rig faces fewer challenges circulating and reconditioning the well, saving time and cost.
In the wellbore stability case, the downhole event detection system may compare measured vs expected density along the string to indicate that a wellbore stability problem exists. Excess material falling into the well affects the average fluid density in unexpected ways. Along-string measurements pick up the density-changing effects of the drilled cuttings and collapsed material. Simultaneously, the hydraulic model accounts for the density-changing effects of the drilled cuttings but not the collapsed material. The resulting mismatch between the expected density and estimated density indicates an active wellbore stability event.
Other applications in downhole event detection include advanced visualisations. Advanced displays of the downhole event detection system show where the expected and measured values differ in time and along the well path. This allows a human to quickly determine where an issue is taking effect in the well to aid in the event response.
The next step
Detecting problems and responding to the well early is essential in reducing both costs and the occurrence of unplanned events. The industry is looking forward to taking the next steps toward autonomous drilling systems. Improved methods of fingerprinting and advanced downhole event detection allow operators to get drilling faster and respond to surprises sooner. Earlier characterisation of a problem allows the crew to form an appropriate response sooner, mitigating an event before it grows in magnitude and scope.
Figure 2. MPD workflow incorporating WDP.
Figure 3. WPD integrated into MPD workflow enables choke control from direct measurement.
Figure 4. Combining MWD and WDP allows the downhole event detection system to compare measured vs. expected values.
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ive years ago, the UK’s North Sea Transition Authority (NSTA) set an ambitious target for the UK continental shelf (UKCS) oil and gas decommissioning industry to achieve a 35% cost saving by the end of 2022. Each year, progress has been tracked, and the latest report published in July 20211 showed that a saving of 23% had been achieved. The NSTA has called for faster decommissioning of inactive wells, with increasing collaboration between and amongst licensees and the supply chain, for example, to combine wells into decommissioning campaigns to achieve cost efficiencies.
Over 8000 wells have been drilled in the UKCS to date. The current active well stock comprises 2625 wellbores with 1736 producing and 871 inactive/suspended.2, 3 With cost and speed high on the industry’s agenda, new technology and processes introduced by innovative supply chain vendors are helping operators to deliver these targets. One area where significant cost and efficiency improvements can be realised offshore is in rigless or offline, rather than rig-based, well intervention. This is particularly applicable in the later and simpler stages of near-surface well decommissioning when all
Stuart Slater, Unity, UK, explains the merits of employing more agile technology solutions for shallow intervention operations.
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permanent barriers have been installed and heavyweight well control is not necessary. This includes the setting of environmental/surface barriers and the removal of near-surface and surface equipment including the casing strings, conductor, and wellhead. By dividing the full P&A sequence into phases and applying fit-for-purpose solutions for each phase and each well, the operator has the opportunity to deliver significant cost savings.
North Sea P&A challenge
This approach has been implemented to great effect at a fully integrated fixed offshore platform in the Northern North Sea, equipped with manned production, drilling and utilities facilities. Operating since the late 1970s, the platform is now undergoing phased decommissioning, with well P&A work currently active.
The operator’s P&A programme had earmarked a number of wells on this platform which were suitable for an offline approach to set shallow plugs in preparation for the removal of the wellhead equipment, however, several challenges needed to be overcome. The well intervention work would need to be conducted while simultaneous rig-based drilling and slickline operations were ongoing at other wells on the same platform, resulting in limited deck space and POB allowance. Height access was also restricted due to the wells being located under the drilling rig. The final challenge was an extremely tight schedule to fit around other planned operations, so the plug setting solution would need to be simple to deploy and compact, yet also manoeuvrable and fast.
Compact technology
To combat these challenges, the operator chose a technology from Unity, which was launched in 2019. The surface intervention system (SIS) can be used for a variety of near-surface operations such as setting shallow plugs and tubing hanger plugs, Xmas Tree removal, well inspection, milling or well-bore clean out, with interchangeable tools on a sectional rod-based intervention system. Powerful hydraulic cylinders apply a push force of 70 000 lbs and a pull force of 40 000 lbs, whilst an ATEX rated motor can be added for a 300 rpm/1200 ft/lbs rotational function, delivering an agile solution to rival conventional intervention methods.
The current model is rated for operations up to 10 000 psi with an integral pressure control package. This uses upper and lower seal cartridges, each with three separate uni-directional seals which straddle the rods to ensure a minimum of two seal contacts at all times. The rods are retained with a rod catcher mechanism which must be operated by two separate personnel before the rod can be released, providing enhanced prevention controls for human error. The seal stack housing also incorporates a grease injection port to allow additional well control measures to be applied if required and allow safe retrieval from the well.
Additional safety aspects include the SIS shear sub which is the tool’s primary disconnect device. In the event of any equipment becoming stuck, the shear sub can quickly be activated, and SIS rods pulled out of hole, leaving behind a standard fishing neck profile.
This year, Unity has developed a data gathering version of the SIS, which utilises the same assembly but deploys ported rods to allow through-rod communication. This further investment in product engineering will allow for enhanced
28 | Oilfield Technology Autumn 2022
Figures
1 & 2.
A lightweight and compact SIS is deployed for surface plug setting operations in a cramped and busy wellbay on a North Sea platform.
pressure control and fluid circulation, improved direct injection, and could lead to live electrical communication, potentially including a live camera feed to give clients instant access to valve conditions or frac sleeve wear.
Enhanced well control
To complement the SIS, Unity has recently developed another technology in the form of a compact shear-seal (CSS) valve. This upgrades the well control offering with a fast-acting isolation function, but ensures the lightweight, compact offering is still retained. The new CSS utilises a hydraulically actuated dual ram but is 50% lighter and 30% smaller than the next closest comparable product, being designed for tight spaces and small rig hatches. Additional models are currently in development to offer solutions for higher pressure or more aggressive fluid environments, which could benefit from the compact design, or potential bespoke cutting requirements in already large stack up designs. The SIS system measures in at 660 mm x 3455 mm and is lightweight at 1060 kg. Adding the CSS increases the weight by 952 kgs. The compact size and reduced weight help improve handling and reduce concerns over structural integrity on late-life assets.
Well intervention often requires multiple vendors with considerable manpower, heavy well control packages and a large wellsite footprint, resulting in significant cost and risk for the operator, especially offshore. While this equipment is necessary for deeper well intervention, the SIS and CSS provide a high performing, compact, and cost-effective solution for shallow operations.
Offline deployment
For this multi-well, surface plug-setting project in the North Sea, the SIS was deployed by Unity as part of a fully managed, independent service. Work on the first two wells was successfully completed in March and May 2022, with a third deployment scheduled for 3Q22. In this third deployment the CSS will be included as part of the well control package, serving to complete the first field application of this new technology.
Unity’s rig-up, for both wells, took place in an extremely confined and busy wellbay below deck. Following detailed pre-job planning, the SIS and the pressure control equipment were quickly mobilised and installed to the Xmas Tree using a small A-frame gantry crane.
For both projects, SIS rig-up and testing were complete in under five hours, then a 4.5 in. bridge plug was successfully set in the well at around 90 ft MD-BRT. The plug was set first time, within 30 minutes of rig-up. Rig-down was complete in around six hours and just one overnight stay was required for two technicians.
Operator benefits
Both completed plug-setting projects delivered significant savings to the operator, with a cost and personnel package reduction of 66% with a 60% faster turnaround compared to traditional solutions. This is particularly important as the industry looks for ways to reduce the unavoidable decommissioning cost burden on many operators.
SIS plug setting work is now planned for a further 14 wells on this platform to support the operator’s wider decommissioning programme. The multi-disciplinary support service from Unity may also include pre and post SIS intervention operations, such as suspending the well or tree removal, thereby delivering further project efficiencies.
The technology offers operators the benefit of an onsite surface intervention system that can be deployed instantly to rectify surface safety concerns or production inhibiting issues, returning wells to a safe or productive status. It has delivered similar savings in other projects around the world, including North Africa and the Middle East, as well as in other European applications. The technology can be mobilised quickly with only 48 hours redress required between deployments.
With targets to reduce near-surface integrity issues in producing wells and the cost of well decommissioning programmes still high on the agenda of the NSTA and other regional authorities, this is one example of how supply chain innovation and pragmatism in developing new technology can meet this need.
References
1. North Sea Transition Authority (NSTA): UKCS Decommissioning Cost Estimate 2021 - 2021 - Publications - News & <br/>publications (nstauthority.co.uk)
2. North Sea Transition Authority (NSTA): Wells Insight Report reveals activity slowdown in the UK North Sea and untapped potential in well maintenance - 2021 - News - News & <br/>publications (nstauthority. co.uk)
3. UKCS Suspended Well Stock (arcgis.com)
Autumn 2022 Oilfield Technology | 29
Figure 3. The Surface Intervention System (SIS) is complemented by a compact shear seal (CSS) valve and small pressure control and operating units.
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Finlay Johnston, 4C Global Consultancy, UK, shares his insight into whether the oil industry is on track for a rig rate super cycle in the North Sea.
ince mobile drilling rigs first appeared on the UKCS in the late 1960s and early 1970s, oil prices have gone through numerous cycles. This has driven rig demand and, consequently, rig price. Looking forward to what could become a super cycle in rig rates, it is crucial to equip ourselves with the best market knowledge we can find to help us chart a course through the challenges to come.
Whilst offshore drilling rigs are unique in many ways, they are also a commodity just like any other: when demand is high, prices are high. It is interesting to note that the market has fluctuated
more in the UK section of the North Sea than on the Norwegian side, even though they both charter very similar, and in some cases, the same type of rigs. The key difference is that, in Norway, rigs tend to be chartered for five years or more at a time, whilst average charter durations are shorter in the UK, resulting in faster changes to pricing.
The UK has therefore always been seen as a rig ‘spot-market’ that does not offer the relative stability of the Norwegian market –or at least that is how it was until everything changed in 2014. Since then, there have been several industry developments which have
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changed what was an almost predictable oil price and rig rate cycle, to a place where market volatility and unpredictability are the norm.
The collapse
In 2014, the oil price collapsed and most of the world’s mobile rigs had no work. At the same time, there was a historically large number of rig owners at play, creating fiercer-than-normal competition for work. As a result, rig day rates reached new lows, and a considerable number of rigs that could not find work were stacked in sheltered waters such as the Cromarty Firth in Scotland. Adding to the ‘perfect storm’ for rig owners was the fact that the drilling industry was carrying an unprecedented level of debt, meaning that fleets required high long-term day rates to service their debt and continue paying shareholder dividends. Adding to the pain in 2014 was the fact that the majority of the world’s 1970s and 1980s-built rigs were nearing the end of their working lives. This was a drilling industry where work prospects had evaporated, large numbers of old rigs stood idle, share prices were tumbling, debt default was escalating, and any road to recovery was hard to envisage.
To survive, drilling contractors needed to adapt their business models quickly and dramatically, through massive cost cutting and debt restructures. This had a very real human cost, with large-scale redundancy programmes of rig crews and onshore staff. It also triggered the industry’s first fleet rebalancing, with owners electing to scrap large numbers of rigs. At first, older units were scrapped. But, as the downturn continued, more than 100 relatively-modern rigs were decommissioned and sent to scrapyards. An industry-wide debt restructure also began, with drilling contractors filing for ‘chapter 11’ creditor protection whilst they renegotiated their respective bank and bond obligations. Tens of billions of dollars of debt were lost
during this process, with many financial institutions recovering only a small portion of their original lending. The result, however, was a leaner and more fit-for-purpose collection of drillers that were able to survive in a low-margin environment.
Following on from this, ‘fit’ drilling companies became easier to compare in terms of their valuation. This in turn triggered the next phase of the post-2014 drilling industry metamorphosis, whereby a programme of consolidation began.
The recovery
The consolidation led to a still-reducing number of drilling companies through mergers and acquisitions, the purpose of which was to reduce the customer’s choice of rig provider, achieve greater market pricing leverage as a consequence, and maximise returns to battle-weary drilling contractor shareholders. As a result of this, the drilling industry will soon comprise of a small number of rig owners, with most electing to become ‘pure players’ by specialising in only one rig type in order to further strengthen their leverage. This small pack of drillers will push hard for rate increase against a backdrop of reduced rig supply and increasing demand driven by higher oil pricing and the need for non-Russian crude.
The drilling industry is comprised of various rig sub sectors such as deepwater drill ships, harsh environment semi-submersibles, and commodity jack ups – to name but a few. Despite the strong market recovery that is underway, each sub sector is recovering at a different speed for a variety of unique reasons. In the UK, harsh environment semi-submersibles have always been prevalent, but this fleet has endured an above-average level of scrapping over the last eight years, leaving only a handful of active and stacked rigs. What is three today would once have been a couple of dozen that were constantly active.
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The main reason for this is that the UK fleet was predominantly older, ‘vintage’ rigs that were ripe for scrapping. Additionally, regional day rates saw one of the sharpest industry falls from circa US$400 000 to US$100 000, resulting in some larger multi-national rig owners losing interest in the basin.
Rig demand and supply
UK rig demand is clearly increasing, especially following on from recent investment tax breaks. However, it is increasing relatively slowly. A slow increase in demand results in a slow increase in day rate increase. This all changes, however, when the region edges close to running out of rigs, and then day rates suddenly surge.
Working out how many rigs are available in the region is not as easy as it may sound, as some active rigs that have near-term contract end dates are highly likely to remain with the same customer if the contract has an option for extension. Several units have been secured either through direct negotiations, or simply by extending contracts. Both are key indicators that there is concern in the boardrooms that costs will escalate, and so the decision has been made to avoid the risk of a sudden increase in day rates, cost of change, and rig acceptance.
The next supply uncertainty relates to a small number of rigs that have avoided being scrapped, but instead have been stacked for years. These require considerable reactivation costs that can be funded by either a confident rig owner or a desperate rig customer. Either way, it is not abundantly clear how these stacked rigs are viewed in terms of supply, and it very much depends on where we are in the cycle.
The final uncertainty relates to incoming rigs. The UK is a protected market, as only rigs with a high technical capability can enter due to legislative requirements. From the rigs that can enter the UK, most are very high-spec units that are happily working in other regions on longer-term high day rate contracts. That said, there are still a few obvious contenders which would sit well in the UK market for drilling, intervention, and P&A, such as Dolphin Drilling’s Bideford and Borgland semi-submersibles, which are currently smart stacked in Norway.
Industry analysts state that there are currently almost four times as many customer rig enquiries as there are available rigs in the UK. This tells us that oil companies are confident about drilling and are in the final stages of their deliberation. With factors such as constantly high oil prices, significant new tax breaks, a new political will to utilise the UK oil resources, and investment flowing into oil companies, one may be tempted to ask why they are taking so long to deliberate when rig availability is already limited? Oil companies will have their own reasons, but what will trigger change is when the realisation that supply is tighter than they thought and the fear of missing out strikes. When customers realise that there is a real prospect of ending up with no rig, rates will spike in the fight for the last rig, and the super cycle will arrive.
Conclusion
In this type of market, there will inevitably be winners and losers. Rig owners will win as revenues and margins increase and rig crews will win as wage inflation kicks in due to limited availability of experienced personnel. Specialist industry suppliers, such as drilling tubular and tool providers (as well as well planning companies) will see a dramatic increase in demand too. The losers will be oil companies who wanted to drill for oil but waited too long and ended up with rigs that were so expensive that they test the limits of the field of economics – or no rig at all.
Whilst non-value adding works would typically be delayed in the current climate, this time there are several operators that are still committed to reducing liabilities that run into hundreds of millions. Again, this will only add to the removal of assets, thus constricting the market further.
So, what about the all-important day rate? In the newly-balanced drilling contractor landscape, and against the backdrop of a clear need for oil, recovery is underway. Consequently, there is no doubt that key locations such as Aberdeen, Scotland, will be energised once again, albeit not quite to pre-2014 levels.
Autumn 2022 Oilfield Technology | 33
Figure 1. Dolphin Drilling’s semi-submersible, enhanced Aker H-3 – The Borgland Dolphin.
Figure 2. The semi-submersible holds a current UK safety case.
Figure 3. The Borgland Dolphin is an ideal contender for both UK and International mid water work scopes.
INOVA Geophysical began exploring digital sensor technology with a solution-focused micro electrical mechanical systems (MEMS) seismic sensor chip in the late 1990s. Designed to overcome the limitations in sensor technology that are currently inherent in analog geophone sensors, the digital sensor helps to eliminate issues with broadband sensitivity and phase. Since the introduction of the MEMS technology, two products – including Vectorseis, a 3C all-digital sensor, and Accuseis, a single-component digital sensor have seen commercial successes on the market. The digital sensor technology is currently in its 5th generation of commercial products, and is continuing to evolve.
INOVA’s Quantum® nodal system was introduced to the market as a fully practical, standalone seismic node and offers advantageous operational properties, compact design, and reliability.
Quantum with Accuseis is the fusion of INOVA’s 5th generation MEMS technology and the Quantum node, creating a product with the benefits of both.
A foundation of research and field knowledge
The 5th generation Accuseis technology is based on a foundation of research and field experiences. The Accuseis sensor is formed from a sandwich of silicon wafers with a tiny mass suspended by etched silicon springs, forming a unit that is about 1 cm.2 The output of the sensor is a ratio of charges on either side of the suspended mass. Updating approximately 156 000 times/sec., the charge ratio is the source of the data stream for digitisation. This technology outputs units of gravity (g) with a very high degree of fidelity.
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A secondary but important benefit is that the unit self-calibrates each time it powers up, and at random intervals while recording. This ensures that the sensor response is uniform, repeatable, and does not age with continued use. The sensor will respond identically during thousands of deployments throughout the product life. Since the silicon chip is tiny and very rigid, the sensor has a resonant frequency of approximately 2000 Hz, which results in amplitude and phase response curves that are above the useful frequency range for seismic data. In effect, the resultant phase and amplitude response of the sensor is nearly flat. Functioning in gravity units from 0 to 400 Hz with a nearly flat phase and amplitude response results in a truly broadband sensor that can overcome the historical limitations of analog geophone technology.
Since the introduction of the digital sensor in the late 1990s, many projects have been implemented with this technology. Originally marketed in a 3C sensor called Vectorseis, the units have successfully recorded data in every environment, with both 3C sensors and 1C sensors. Projects with over 180 000 live channels have been successfully completed with Accuseis sensors.
A data comparison from North Africa demonstrates the advantages of the technology. In this example, a 2D line was recorded with coincident sensors, including single high-sensitivity geophones and the Accuseis sensor. The 2D line was shot and recorded into two systems simultaneously. This set-up eliminates environmental issues and potential source variances, and provides data sets that can be utilised to compare sensor responses (Figure 2). In this case, the Accuseis sensor produced
Jason Criss, INOVA Geophysical, USA, discusses the use of a combination of digital sensor technologies to meet the demands of challenging projects in regions around the world.
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a stronger amplitude response when compared with the analog 5 Hz high-sensitivity geophone.
In a second data example (Figure 3), the Accuseis data is compared with the results of legacy seismic data. In this example showing fully-processed data, the reshoot using the digital sensor resulted in higher resolution and greater fidelity.
The Quantum node is under improvement through the development of new features, utilising high-sensitivity geophones as the initial sensor technology. The original Quantum node is a small 650 g full-featured recording node that records seismic data continuously for up to 50 days with a high-fidelity, industry-standard, dynamic range and sensitivity. A new development, HyperQ, utilises a low-power, long-range wireless technology to transmit data over long distances. The technology enhances the original product by allowing the status of deployed units to be monitored at ranges of as far as several kilometers, depending on terrain and the antenna height.
The technology helps makes seismic projects more efficient and operationally-flexible, which in turn makes them more environmentally-secure, profitable and safer to operate. The addition of the Accuseis digital sensor as a replacement for the geophone results in a recording system with strong operational properties and a true broadband sensor.
Flexibility and feasibility
Areas with diverse topography, and zones ranging from urban environments and dense jungles, to shallow swamps and arid deserts, create tremendous operational challenges for seismic crews. The flexible technology can be configured and deployed to acquire data for many weeks, using duty cycling which turns nodes off during periods of no shooting activity and then begins recording at preconfigured times. This capability means that crews can work with a two-touch strategy, where the receiver station is visited once for deployment, and a second time for retrieval once the shooting has progressed past the area. This simplifies operations and the environmental impact, and is a key feature when analysing permitting issues.
Combined with HyperQ technology, the deployed Quantum nodes can be scanned for daily quality control through telemetry. Since the HyperQ technology is effective for use across long ranges, quality control can be accomplished with a variety of strategies including fixed masts, drive-by utilising work vehicles, and fly-by utilising drones. Drone QC has been proven effective in many regions, and is a growing technology that is ideal for this purpose, especially when ground access is restricted by wet areas and permit issues.
Furthermore, Quantum can be configured to work with a marsh geophone. This delivers a solution for areas where water is expected to cover zones of the project. When set up on purpose-built floats, marsh geophones are deployed in the soil at the water bottom, while the Quantum units remain active and record above water. This capability allows crews to maintain a consistent system type with a flexible and adaptable geometry that makes the Quantum solution a feasible and optimal one for challenging projects. The technology has made possible the acquisition of data in challenging environments around the world.
Technology fusion
The fusion of the Quantum technology with the Accuseis technology expands the capability of the system by providing a broader spectrum of user choices and solutions for deploying seismic equipment in any type of landscape. The technology is an effective solution in terrain types ranging from deserts with unrestricted access, to areas with dense jungles. The Accuseis technology is a seismic solution that helps overcome the technical disadvantages of the geophone, and is a truly broadband solution with a uniform phase and amplitude response. These technologies can help to expand and meet the needs of challenging projects in many regions.
36 | Oilfield Technology Autumn 2022
Figure 1. Accuseis sensor.
Figure 2. Stack sections from the 2D line show differences between the Accuseis sensor response (top) and the 5 Hz high-sensitivity analog geophone response (bottom).
Figure 3. Processed data comparing Accuseis sensor data against legacy data from the same location. Legacy data on the left and Accuseis data on the right geophone response.
Suki Gill, Enteq Technologies, USA, details how the latest MWD technology is helping advance the directional drilling industry.
Watching a rig crew on a mission to drill a borehole, plant a bomb and save the world in Armageddon was a moment of inspiration for many petroleum engineers working in the industry today. In the 1998 Michael Bay spectacular, the crew is on a mission to excavate and destroy an
asteroid that threatens the planet. The plan succeeds, and the crew are global heroes.
Needless to say, the technology and drilling process depicted in the movie is not an accurate representation of drilling today. The economics of drilling have shifted; it is known that the
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pandemic has hit the oil and gas sector particularly hard. It was always a tough job, but it has become a whole lot tougher.
Many of these trends are irreversible. But the oil and gas sector has always adapted, survived, and ultimately thrived in the face of change. If we can think smarter – and fairer – about the technology drilling companies (specifically directional drilling companies) rely on to do their job, the industry will flourish again. Enteq Technologies is therefore is taking a new approach to the measurement- and logging-while drilling (MWD/LWD) market.
Different days for directional drilling – what has changed?
In 2014, in British Columbia, Canada, drilling a well could take 24 – 27 days. Today, a similar well could be drilled in
just 7 – 10 days. That is beneficial for the operator but not good news for the directional drilling company. Since directional drilling companies are paid a day rate, not a lump sum when the work is completed, drilling a well in less time decreases company revenue. For example, if one assumes a CAN$6000 day rate, the 2014 British Columbia job would be CAN$144 000. Compared to today’s drilling outlook, the job would only be CAN$42 000.
This is just one example, but the problem is widespread. The oil and gas market has always been cyclical, but a number of trends plus the pandemic have eroded the sector’s economic stability over time. Today, WTI stands at a reasonable US$104.41/bbl, but last year in 2021, it went negative for the first time in history and was predicted to tip US$100/bbl in the near future. Rig counts were slashed, as were day rates. This trickles down to hiring, and putting pressure on companies to rely on fewer employees. Now the numbers look healthier again – but for how long?
At the same time, the jobs themselves have become more demanding. Operators want to go deeper and faster, and demand that even small and mid-sized directional drilling companies have the latest MWD/LWD tech, such as resistivity-at-bit solutions. There is also increasing demand for hot tools capable of operating in high-temperature environments. Though this is still a relatively small proportion of the total market, it may well increase further as sectors such as geothermal energy expand.
The geography of the industry is changing too. The Middle East remains a juggernaut and US shale strength continues, but around the world operators are looking again at previously unattractive or uneconomic plays and re-evaluating their feasibility. To make these plays economic means keeping an iron grip on the cost per barrel.
There is a degree of geographic disparity to contend with. While North American directional drilling service providers may have to pay top dollar for the latest at-bit solutions, it is at least available to them. This is not always the case for those drilling in China, for example. Often, it takes years for tech to become widely available to independent service companies in the rest of the world, and even then, still at
38 | Oilfield Technology Autumn 2022
Figure 1. Enteq Technologies' in-house engineering team.
Figure
2.
Final equipment checks.
premium rates – potentially with forex disadvantages versus the US dollar, too.
High time for high tech
So, what can we do about it? We may not be able to do much about the underlying trends changing the economics of directional drilling, but we can offer technology to drilling companies to meet these challenges head-on.
For example, automation and IoT can be critical to assuaging cost and labour pressures. With day rates depressed, it can be painfully expensive to deploy fully qualified MWD engineers to every job. If COVID has taught us anything though, it is how effective remote working can be. So, by automating the operation of MWD/LWD tools and adding remote telemetry, highly-educated workforces can work from a central office (or a virtual one even, working from home) and from there they can look after a portfolio of five or six rigs rather than having to be deployed, on-site, to one. As a bonus, this also fits neatly with operators’ drive to reduce overall personnel footprint on rigs.
For example, leading technologies today have built-in artificial intelligence (AI) to simplify decoding, meaning minimal input from the MWD tech on location. If and when there are decoding issues, that MWD tech can pick up a phone to a team of dozens of software engineers working around the clock to help them fix the problem. For the drilling company, it means a smarter, leaner operation with less need to deploy top-rate talent to every job and the ability to manage operations remotely, allowing them to take on more work and reassign money to CAPEX to invest in getting top tech into the fleet.
An expanding range of data types also works to the benefit of drilling companies. Better downhole batteries
enable real-time transmission of metrics such as collar RPM and BHA health. Real-time measurements then allow for drilling optimisation, pushing the equipment as hard as possible without exceeding risk thresholds the sweet-spot, so to speak. These are enhanced further by advances in electromagnetic (EM) telemetry systems boosting the rate and reliability of data transmission versus older EM or mud-pulse systems.
Newer sensor types such as micro electrical mechanical system sensors (MEMS) are also pushing the envelope on MWD design. If traditional sensors are hard disk drives, these are solid state – a genuine leap forward in technology with greater resilience to shock and vibration, but at a higher price point. They enable real-time measurements such as stick-slip to further optimise drilling and get the most out of equipment, though it is important not to over-specify where cheaper legacy systems are fit for purpose.
Upgrading downhole measurement
The tech is there to help directional drilling companies face their challenges head-on, but for companies in North America and beyond it can be difficult to cost-effectively access the best equipment for the task at hand. This needs to change.
We likely cannot expect another box-office blockbuster where drilling companies save the day anytime soon. Too much has changed since 1998. Although hero-status is too much to ask, directional drilling service providers worldwide deserve support. Enteq Technologies aims to offer that support by providing access to effective MWD and LWD tools, integrated into bespoke solutions based on real-world, downhole directional drilling expertise.
Mojtaba Moradi and Michael R Konopczynski, Tendeka, UK, analyse the role of flow control devices in improving the performance of matrix acid stimulation operations in carbonate reservoirs.
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The use of hydrochloric acid to stimulate oil wells began in 1932. However, effective matrix acidising stimulation of heterogeneous carbonates, especially across long intervals, has long been a challenge. This is because a sufficient chemical reaction rate to the rock is required to establish a controlled flow and deep-reaching penetration into the formation matrix without excessively increasing bottom hole pressure that can cause the formation to break down.1
The issues associated with acid placement in carbonate reservoirs are numerous: from dealing with a complex depositional environment to issues around the effect of dissolution, recrystallisation, and variable permeability caused by natural fractures, faults, low matrix permeability and formation damage from pre-production or production operations. Reservoir fluid properties including saturation, relative permeabilities and mobility issues, also influence the effectiveness of the stimulation.
The selection of stimulation fluid, diverters, pumping rates, treatment pressures, and the correct planning of the pumping schedule are therefore, all crucial to the effectiveness of the stimulation.
A new autonomous outflow control device Addressing such complex reservoir properties and optimising the acid treatments for even fluid distribution along the wellbore can be problematic. For instance, thief zones, fractures, and hyper-reactive zones ‘stealing’ all the treatment and unsuccessful diversion for less conductive zones are culprits of inadequate and unoptimised acid stimulation.
Tendeka has developed FloFuse, a new autonomous outflow control device, to provide mechanical diversion during matrix stimulation (Figure 1).
The active flow control device was initially designed to control the injectant conformance in injection wells, and could significantly help to improve the distribution of stimulation acid, especially in carbonate formations. As an injection rate-limiting technology, the device ensures proportional distribution of treatment
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fluid along the full length of the wellbore and between laterals. It allows repeat stimulation of carbonate reservoirs, providing mechanical diversion without the need for coiled tubing or other complex intervention.
It has two operating conditions, one, as a passive outflow control valve, and two, as a barrier when the flow rate through the valve exceeds a designed limit, analogous to an electrical circuit breaker. The natural state of the valve, which is mounted into the base pipe or screen section, is in the open position (biased open).
The injection outflow under normal operating conditions passes through the ‘normally operating nozzle’ and through the screen as required, as depicted by the blue baseline performance curve in Figure 2.
Once a zone has been sufficiently stimulated by the acid and the injection rate in that zone exceeds the device trigger point, the device in that zone closes and restricts further stimulation. Acid can then flow to and stimulate other zones. This eliminates the impact of the thief zone on acid injection conformance and maintains a prescribed acid distribution. The process can be repeated later in the well’s life to re-stimulate zones and can be retrofitted in existing completions or be used in a retrievable completion. As a spring-loaded valve, this trigger point can be altered based on the design parameters, including the nozzle diameter and spring constant.
Dynamic response to acid stimulation
Conventionally, passive flow control devices, which are completions with a fixed configuration that influence the well’s outflow, have been installed in wells. If the well completion is not properly designed, its impact is less effective, especially if dynamic changes in reservoir properties happen which is often the case for a well with regular acid stimulation operations.
FloFuse restricts the injection of fluids into dilating/propagating fractures, faults, and features, thus mitigating disproportional injection, which could potentially reduce the performance of the operation.
If the devices are installed permanently as a part of a downhole completion in the well, the completion would be used to optimise the fluid injection, plus it could be used as a mechanical diverter for acid stimulation negating the need for intervention. It could also be installed temporarily as a mechanical diverter and retrieved once the stimulation is finished. With either solution, acid could be bullheaded from the surface.
Several experiments including water, polymer and air injection have been performed to characterise the valve. The characteristics could be described for example by the curve of differential pressure drop (DP) across the device against flow rate passing through.
Figure 3 represents the performances of different sizes of devices namely: 2.2 mm, 3 mm, and 4.5 mm, for water-like fluids.
Modelling and operational design workflow
Once the completion is installed and acid bullheaded from the surface, FloFuse allows acid injection while controlling the flow of acid into higher rate intake (permeability) zones. Thereby, ensuring effective fluid placement across the whole length of the wellbore being treated initially, while each discrete zone is effectively acidised. As the volume of acid and injection rate is important in carbonate acidising to get the appropriate wormhole, this concern should be included in pump rate planning.
Once the FloFuse completion nominal design has been completed, additional sensitivities can be run to evaluate the impact on production or injection profiles from changes in the simulation treatment design. In addition, an understanding of the mechanisms that may cause deviation from the planned acid injection rates and distribution should be noted. Ultimately, the treatment design needs to be confidently executed in the field as per the design plan.
42 | Oilfield Technology Autumn 2022
Figure 1. Cross-section of FloFuse valve, open position.
Figure 2. The fluid flow path through the device mounted on the screen and its housing.
Figure 3. The FloFuse valve performance for injection of water-like fluids.
Figure 4. Production profile before and after stimulation operation for Well A.
Case study: acidisation of a vertical production well using FloFuse
Well A, located in the Middle East, passes through four main reservoir layers. It has been extensively studied and the pumping schedule and post-evaluation study of the real stimulation operation are provided.2
During pre-stimulation conditions, the well could only produce 25 MMScf/day of gas with a wellhead pressure of 3400 psi. Also, the contributions from the layers are non-uniform and zones 4 and 1 produce almost 51% and 32% of total produced gas respectively, while the other two zones’ share is only 17%.
The post-evaluation study shows that although the bottom layer was treated , the top layer may have been overtreated as evidence shows the existence of crossflow inside the tubing (Figure 4). This is mainly due to heterogeneity in the layer’s properties including skin, permeability, and reservoir pressure.
A static wellbore model was set up using a commercially available software. The result from the model, which agreed with the output of PLT data taken pre-stimulation, showed that more than 51% of gas was produced from layer K4 when assuming the gas production rate is 25 MMSCF/D. To investigate the impact of a new diverter (completion) on the acidisation performance for this well, a retrofit FloFuse solution was evaluated.
This was comprised of four completion zones separated by four annular flow isolations placed at the border of layers. Devices are mounted on 5.5 in. joints to be retrofitted inside the current completion. For this example, the use of 4.5 mm FloFuse devices which close at a DP of 200 psi is recommended.
The assumed objective was to stimulate the well to significantly enhance production from low productive zones while reducing the formation damages at higher productivity zones.
At the outset, an acid injection rate of 15 bpm was modelled. Due to the impact of the FloFuse devices on flow profile, the acid intakes of the zones are more balanced compared to the base case well scenario. For example, the contribution from zones 2 and 3 has increased to 28% compared to 17%, even at the beginning of the process. However, layer 4 is expected to still take most of the fluid (51%) at this stage. Here, it is assumed that the acid will be stimulating layer K4 more rapidly and to a greater extent, compared to other layers. At this stage, it is assumed that once the skin value decreases to 20% of the initial value, the stimulation of the layer is sufficient and the FloFuse devices should close.
The reduction of skin at each layer is associated with a higher intake of acid from that layer. Once the new skin value for the layer is established, the DP across the devices reaches the trigger point and the valves at this zone are tripped (closed).
To move to the next stage, the operator should always consider the impacts of the closed valves on the DP across open devices to avoid premature closure of valves at other zones. Here, it was decided to lower the injection rate to 14 bpm to avoid this, most notably, at zone 1, increasing the margin of DP from the closing pressure of 200 psi to allow sufficient stimulation. If more time is required to inject a sufficient volume of acid to reach the desired skin, the injection rate should be lowered further.
Once the skin value decreases to 50% of the initial value, the valves at this zone would also close, so the acid would be diverted to zones 2 and 3, which had the lowest contributions initially.
Considering the number of closed valves, as well as the results of earlier stages, lowering the injection rate to 12 bpm is necessary to remove damage from these zones completely without any valve closing.
Once the new skizns are established, the operator could decide to stop the operation or reset the valves to open positions and perform another stage of stimulation, if further stimulation is required.
For instance, once all valves are open, the new profile which is a more balanced profile with higher contribution from zones 2 and 3 is achieved. Please note that the required time to establish the new skin at each stage is not considered in this study and could be estimated using available software.
The results from post-stimulation modelling, as shown in Figures 5 and 6, illustrate the success of FloFuse completion to improve the acidisation operation of the well.
The data not only shows that a more than threefold increase in production rates (78MMSCF/day) from the well stimulated using FloFuse diverters could be achieved, but also that the new production profile from the well is more uniform and no crossflow between the layers is observed.
References
1. HARRISON, N. W. “Diverting agents - history and application”. Journal of Petroleum Technology, 24 (5) (1972) pages 593–598. SPE-3653-PA. https://doi. org/10.2118/3653-PA
2. SAFARI, ALIREZA R; PANJALIZADEH, HAMED; POURNIK, MAYSAM; JAFARI, HAMED AND ZANGENEH, ALIREZA. “A comprehensive method for diverterperformance evaluation during stimulation of long-interval heterogeneous reservoirs: A case study”. SPE Prod & Oper 36 (2021) pages 22–33. doi: https://doi. org/10.2118/200135-PA
3. HALL-THOMPSON, BRYAN; ERNESTO, ARIAS ROMMEL; ABDULRAHMAN, NUTAIFI; AND ABDULAZIZ ALSUHAIMI. “Acid stimulation - best practices for design, selection and testing of acid recipes in low permeability carbonate reservoirs”. Paper presented at the International Petroleum Technology Conference, Dhahran, Kingdom of Saudi Arabia, January 2020. doi: https://doi.org/10.2523/IPTC-19690-MS
4. HALL-THOMPSON, B; ARIAS R.E; UTAIBI A.A; AND MASHAT B. “Extending technology l limits – successful application of multi-stage open hole horizontal completion in offshore environment”. SPE 188712-MS presented at the Abu Dhabi International Petroleum Exhibition & Conference held in Abu Dhabi, UAE, 13-16 November 2017
5. MOHD ISMAIL, ISMARULLIZAM; KONOPCZYNSKI, MICHAEL; AND MOJTABA MORADI. “A game changer for injection wells outflow control devices to efficiently control the injection fluid conformance”, Paper presented at the Abu Dhabi International Petroleum Exhibition & Conference, Abu Dhabi, UAE, November 2019 doi: https:// doi.org/10.2118/197612-MS
6. MORADI, MOJTABA; ZAREI, FARAJ; AND MORTEZA AKBARI. “The improvement of production profile while managing reservoir uncertainties with inflow control devices completions”. Paper presented at the SPE Bergen One Day Seminar, Bergen, Norway, April 2015. doi: https://doi.org/10.2118/173841-MSq
Figure 5. Production contributions from each layer for different scenarios.
Figure 6. Predicated production profile from Well A: post-stimulation.
Autumn 2022 Oilfield Technology | 43
44 |
fficiency has arguably been the single most prominent theme driving oilfield decision-making over the last decade.
Even as the macro environment has improved and crude prices have risen from historic lows to near decade highs, it has remained a top priority. This is especially true in the high-risk offshore environment, where operators continue to seek out new and innovative ways to lower OPEX, lower emissions, reduce headcounts, and expedite time to first oil/gas.
While significant strides have been made to improve operational efficiency both onshore and offshore in recent years, untapped opportunities exist to realise further gains through technological adoption and better project execution. The post-drilling phase, in particular, is an area that has been ripe for optimisation, as it is often plagued by inefficient use of manpower, increased logistics complexity, and high safety risks.
As this article will discuss, by integrating key post-drilling well services and bringing them under one supervisory umbrella, operators can streamline their activities and capitalise on several benefits. Among these are a 50% reduction in contractor headcount, a 30% reduction in rig time and associated carbon footprint, and a 30% reduction in total post-drilling OPEX.
Pain points of the post-drilling phase
Operators have traditionally been forced to take a segmented approach (i.e. multi-vendor) when it comes to the post-drilling phase of their wells. On a typical rig, it is not uncommon for four to five separate suppliers/technology providers to be awarded contracts for liner hangers, wellbore cleanup, tubular running,
Kevin Thorpe, Weatherford, UAE, outlines how a streamlined, integrated approach to oilfield operations could help improve the efficiency of the post-drilling phase.
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completions, fishing, etc. As many as 10 – 25 people may be present onsite to perform the required duties (depending on the complexity of the operations).
Careful planning and coordination between parties is required to ensure that the various tasks and load-outs take place smoothly and safely. The bulk of this planning occurs weeks or even months before any of the supplier teams have set foot on the rig during completing the well on paper (CWOP) meetings. However, there is often a divergence between what is perceived to work in theory (i.e. on paper) and what actually works on the rig (i.e. in practice). This inevitably leads to inefficiency when activities begin, as supplier teams are forced to work around each other, deviate from plans, and adapt on the fly.
The frequent lack of cross-functional training amongst teams further magnifies these issues. In many cases, each person is assigned a specific task on the well and their presence may only be required periodically for a few hours at a time. The time in between work periods is effectively non-productive, but is nonetheless included in day rates.
Higher costs are also incurred with larger crews due to the need for more helicopter trips, food, beds, etc. Logistics are also made more complex because of the various load-outs from multiple vendor bases, crew mobilisation and demobilisation, crane lifts, and backload of empty shipping containers. All of these inefficiencies ultimately increase costs and risks for the operator. However, they can be avoided.
Rig efficiency also directly correlates with carbon footprint, as every additional day or hour it takes to complete the well increases the amount of fuel burned in gas turbines or diesel engines used for power generation. Over the life of the rig, the total reduction in the runtime of onboard engines can result in significant emissions reductions.
Embracing an integrated approach
An integrated post-drilling approach is one where siloed teams from multiple suppliers are replaced with a single, multi-disciplinary crew that is cross-functionally trained. In addition to maximising the productivity of each individual in the crew, the use of one vendor allows for more effective planning and early identification of risks, standardisation and consistency of work practices, as well as less interface complexity for the operator.
The concept differs from traditional bundling arrangements in which several discrete services are ‘shrink wrapped’ at a discounted rate. The objective of an integrated approach is to drive value, unlock synergies, and reduce the total cost of ownership (TCO) by enabling OPEX reductions that exceed any potential monetary savings that might be achieved by awarding separate contracts to multiple vendors.
This was the primary impetus behind Weatherford’s development of COMPLETE Post-TD Optimised Solutions. This is a holistic turnkey service solution that combines the post-TD phases of the well lifecycle to streamline operations and communications, improve efficiency, and decrease costs from load-outs to well completions. The offering is based on a complete the well in practice (CWIP) methodology. CWIP bridges the gap between a traditional CWOP and service execution by emphasising close coordination with the operator to ensure that plans are practical and align with all relevant key performance indicators (KPIs).
With this solution, operators have a single touch point for all post-drilling activities, including liner hangers, wellbore cleanup, tubular running, completions, and fishing. Competency mapping takes place to ensure that crews are fit-for-purpose and can be maximally productive given the unique requirements of the rig/operation. Once onsite, service delivery teams are responsible for all procedures, assessments, contingency plans, action reviews, time analyses, and well reporting. The goal is to facilitate effective communications across the entire well delivery timeline and drive consistency and repeatability from well to well and location to location.
Although COMPLETE was not explicitly designed to reduce persons on board (POB), it is an indirect benefit of using a singular cross-functionally trained team. In real-world applications, post-drilling contractor headcount reductions on the order of 40 – 50% have been achieved.
POB reductions are also made possible by leveraging key technologies for remote monitoring and automation. Some specific examples include:
Automated connection integrity
Vero is an automated TRS system designed to enhance connection integrity by automatically making up premium threads and autonomously evaluating the makeup data to the OEM criteria. Automated makeup enables precise control of the process,
46 | Oilfield Technology Autumn 2022
Figure
1.
Inefficient use of manpower has historically plagued post-drilling operations.
Figure
2. CWOP vs CWIP methodology.
Subscribe online at: www.hydrocarbonengineering.com/subscribe Worldwide Coverage For in-depth coverage of the global hydrocarbon processing sector 15 South Street, Farnham, Surrey, GU9 7QU, UK T: +44 (0)1252 718999 E: info@palladian-publications.com
independent from any operator-specific influences or other human factors. Autonomous evaluation eliminates subjective graphical interpretations. The system controls the entire makeup process and evaluates makeup data with a resolution 10 times more refined than the human eye can see on the Joint Analysed Makeup (JAM®) screen.
Automated control-line system
The automated, control-line, arm manipulating and positioning (AutoCLAMP) system remotely guides the control line as tubing is run in the hole. The system also positions the control line in proper orientation to the pipe to ease installation of control line clamps.
Real-time monitoring system
AccuView is a software and hardware package used in conjunction with existing liner equipment. With the solution, onsite personnel can establish a remote connection with regional and global subject matter experts (SMEs) during all stages of work execution. AccuView also creates job-specific procedures, checklists and other associated paperwork. The real-time features allow for an overlay of the planning stage data against the real-time rig data so that analysis of the torque and drag can take place. Alerts are set based on the actual well data as opposed to calculated values. Experts sitting in any location around the world can view the live data stream to assist the field engineers and ensure that the job is executed in the most efficient possible manner.
RFID-enabled completions tools
Radio Frequency Identification (RFID) technology can help improve post-TD efficiency by reducing time and increasing flexibility. Tools can be actuated remotely an unlimited number of times without pulling out of the hole. Used as a complete system, RFID-enabled
downhole tools reduce total operating hours and exposure of field personnel and can reduce completion installation time by as much as 60%.
Depending on operator requirements, any combination of hardware and software technologies within Weatherford’s post-TD portfolio can be integrated into the solution package. The technologies are designed for ‘plug and play’ use and are fully managed by the onsite team.
Results
COMPLETE solutions have been deployed in several deepwater projects for independent oil companies (IOCs) in both onshore and offshore applications across the globe, including in West Africa, Norway, South America, the US, and Australasia.
One particular case involved the fabrication, delivery, and installation of liner, gas-lift, and completion equipment to support production on three platforms at one of the largest fields in the North Sea. The two primary objectives of the operator were to:
Ì Provide a single point of contact for logistics and planning, as well as improve the interface between key third-party service contractors on the platforms.
Ì Reduce headcount on production platforms to decrease expense and minimise personnel exposure to mitigate everyday risks associated with working at a remote offshore location.
Having experienced performance issues with incumbent equipment providers, the operator elected to bring a COMPLETE team in to coordinate the roles of third-party contractors. The team also handled logistics, installed multiple product packages, and ran and installed liner, completions, and gas-lift equipment. This allowed for a POB reduction of 55% versus previous similar projects.
Additionally, by handling all logistics, the team was able to minimise the number of offshore supply trips and lifts to the platform. The operator worked with the same crew during each phase of the operation. Overall, the integrated post-drilling approach allowed the operator to deliver completions 30% more efficiently (i.e., 30% reduced rig time) than the previous incumbent’s best benchmark.
Conclusion
Over the past decade, the macro environment for oil and gas producers has improved dramatically. However, volatility in global markets remains a concern. In this environment, operators face the difficult challenge of having to do more with less. While this holds true across all operations, it is particularly the case in offshore deepwater plays, where higher costs and risks create little margin for error when it comes to bringing wells online.
Significant strides have been made since the start of the pandemic to streamline operations, particularly with respect to drilling. However, the post-drilling phase remains an area that all too often is plagued by high costs, logistics complexity, and increased risk for both operators and oilfield service providers. COMPLETE was developed to address these issues by enabling operators to bring all post-drilling activities under the remit of a single, multi-faceted team focused solely on maximising efficiency, minimising risk, and reducing TCO.
48 | Oilfield Technology Autumn 2022
Figure 3. POB comparison of conventional vs integrated approaches.
Figure
4.
Summary of benefits when deploying integrated Post-TD optimised solutions.
In its efforts to maximise hydrocarbon recovery from reservoirs, the oil and gas industry must contend with other fluids and solids that inevitably come along for the ride. Produced water presents a particular management challenge at the surface. By some industry estimates, 7.5 barrels of saltwater are produced for every barrel of crude oil, and 260 barrels of water are produced for every million ft 3 of natural gas. 1
The Permian Basin that spans Texas and New Mexico currently produces 15 million bbl of produced water each day (MMBWPD) – 10 MMBWPD from the Delaware Basin and 5 MMBWPD from the Midland Basin. The Permian’s cumulative produced water volume is expected to rise to 19 MMBWD by 2026.
Some produced water is reused for fracking. But even if operators sourced 100% of their frac water from this source, the volume would only offset 30% of the produced water extracted each day. Some 10 MMBWPD would still need to be disposed of in saltwater disposals (SWDs).
B3 Insight, a water data analysis company, estimates that to handle
the anticipated increase in produced water volumes, the Permian Basin will need another 100+ new facilities in the next five years – at a cost of more than US$400 million.
The capacity of an SWD well is calculated as the BWPD injection rate based on a maximum allowable injection pressure. Many SWDs hit their maximum allowable pressures long before they hit the calculated injection volumes. As a result, ‘utilisation’ – actual injection vs calculated capacity – is far below predicted.
Why do SWD wells fall so short in their daily injectable volumes? The water typically contains dissolved salts, solids like iron and scale, paraffin, and asphaltenes, and naturally occurring radioactive materials – all of which create significant disposal challenges for the 170 000 water injection wells across the US.
The solids in produced saltwater can plate out on the reservoir surface during injection, preventing water migration into the rock and increasing back pressure.
In addition, small amounts of hydrocarbon contaminants in the
Jonathan Rogers, Dr. Megan Pearl, Dr. Amir Mahmoudkhani, Tom Swanson, and Corey Petro, Locus Bio-Energy Solutions, USA, review some recent advances in biosurfactant-based saltwater disposal additives and their effects upon water disposal rates, injection pressures, and the carbon footprint of operations.
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saltwater can create emulsions in the wellbore, which further reduce injectable volumes. As a result, many disposal wells are operating under predicted injection capacity during a time when increasing hydrocarbon production is feeding a demand for greater water disposal.
Drilling new injection wells is not such a straightforward solution to this disposal challenge. SWD activities are increasingly linked to localised seismic activity in certain parts of the US, prompting regulatory agencies to place new restrictions on the industry. The number of seismic events in Texas has increased dramatically in recent years. According to research from the Bureau of Economic Geology at the University of Texas in Austin, more than 200 earthquakes of magnitude (M) 3 and greater struck the state in 2021 – the majority of them in the Permian Basin. This is more than double the 98 recorded in 2020 and roughly four
times the number of M3+ quakes measured in 2019. 3 To alleviate seismicity issues, both New Mexico and Texas established Seismic Response Areas (SRAs) in late 2021, which forced operators to reduce saltwater injection rates in seismically active areas. As a result, over 6 million bbl of water from the SRAs must be transported to other locations for disposal.
Better SWD through chemistry
Injection well operators have turned to chemical solutions, such as acid and surfactant combinations, to help increase injectable water volumes by dissolving or mobilising organic and inorganic solids that restrict injection in the disposal reservoir. Many of these conventional solutions only provide short-lived injection improvements and must be coupled with expensive well intervention methods to boost injectivity.
FloBoost,™ a new line of biosurfactant-based SWD management additives, were developed to reduce costs and increase efficiency of SWD wells in ways that traditional chemistries cannot. Conventional oilfield surfactants are synthesised from petroleum feedstocks and tend to have higher usage costs and carbon footprints. FloBoost additives share unique physicochemical properties with Locus Bio-Energy Solutions’ other fermentation-produced biosurfactants to improve a range of oilfield operations – at a fraction of the dosage and with minimal environmental impact.
Fermentation-produced biosurfactants have unique structures with multiple chemically active sites that allow for improved functionalisation and surface adsorption properties – a contrast to conventional surfactants with a limited number of sites. In both laboratory and field studies, the complex structures of biosurfactants yield interfacial properties that outperform conventional surfactants at extremely low dosage rates.
Interfacial tension (IFT) reduction is a key metric of surfactant performance. Biosurfactants outperform surfactants by penetrating and dispersing inorganic and organic solids that choke the injection well. Biosurfactants also possess unique adsorption/desorption characteristics, delivering long-term wettability alteration and organic deposit removal – properties that immediately reduce injection pressures and increase water injection volumes.
Critical micelle concentration (CMC), which is the concentration at which surfactants self-assemble into micellar structures, is another key performance metric. Many biosurfactants have CMCs of less than 200 ppm, a fraction of the CMC value of most conventional surfactants. As a result, biosurfactants reduce IFTs and alter surface wettability at much lower dosages than many hydrocarbon-based chemistries.
Figure
ppm treatment rate,
water samples
an improvement of nearly 39% in injection rates compared to the
chemistry.
Biosurfactants are robust and highly stable at temperatures greater than 300°F. They are also produced from sustainable raw materials, with no live microbes or components that support microbial growth. As a result, these 100% natural, low-carbon additives minimise a SWD operation’s carbon footprint while helping meet ESG goals.
50 | Oilfield Technology Autumn 2022
Figure
1. In
rapid filtration
tests,
FloBoost-treated water samples pass through Millipore filters at
an injection rate ten times faster
than
a nontreated
sample.
2. At a 50
the FloBoost-treated
demonstrated
incumbent
Enhanced SWD efficiency at reduced treatment costs
The unique properties discussed above help biosurfactant-based additives address many of the critical challenges facing SWD operators.
Reducing injection pressure
By keeping solids dispersed and suspended in the water, these biosurfactant-based injectivity aids help prevent plugging of rock pores and maximise injection volumes at a given maximum allowable injection pressure, thus maximising the operating capacity of the SWD well. Reducing injection pressure minimises power requirements for injection pumps, offering savings to operators.
In addition to reducing solid deposition, the additives can penetrate and disperse existing filter cakes and increase the effective permeability through these deposits – further increasing injection rates. Finally, by reducing IFT and promoting water wetting of the rock surface, FloBoost additives reduce capillary pressure and promote water flow into the pore space, resulting in deeper penetration into the rock at lower injection pressures.
Minimising emulsions formation and blockage
Although significant effort is made to separate valuable hydrocarbons from saltwater before disposal, no treatment is 100% effective. Even trace amounts of hydrocarbon carryover can create emulsions in the wellbore that reduce water flow into pore spaces, resulting in increased injection pressures and reduced volumes. The biosurfactant-based additives have been shown to effectively break up oil-in-water emulsions and keep oil dispersed in the water, with better efficiency and at lower dosages than synthetic surfactants.
Recovering more skim oil Biosurfactant-based additives are shown to minimise the frequency of filter changes and allow the operator to recover more sellable skim oil – both of which improve the profitability of SWD operations. The novel additives can also benefit pad remediation efforts in the SWD system by reducing the additional person-hours and chemicals needed to clean tanks and remain in operation.
Providing flexible treatment options
The biosurfactant-based injectivity aids can be applied alone or in combination with acids and other conventional stimulation chemistries, making them a robust and flexible treatment solution in a wide range of downhole environments.
Proving biosurfactant potential in SWDs
While early on in its commercialisation, FloBoost SWD injectivity aids have demonstrated performance benefits within laboratory and in-field testing. The methodologies used allowed for a quick and definitive performance comparison between FloBoost and conventional SWD additives, with repeatable quantitative and qualitative measures.
Lab filtration testing
In rapid filtration tests in the lab, a series of high-solids Permian SWD water samples – a blank, a FloBoost-treated sample, and an incumbent additive sample – were passed through 0.45-micron Millipore filters at an injection pressure of 15 psi. The injection
rate, measured as the time for 100 ml of water sample to pass through the filter, for the blank sample was 3 minutes and 30 seconds (Figure 1). The long injection rate was attributed to the undispersed solids and oily contaminants quickly settling on and clogging the filter.
By contrast, the FloBoost-treated water sample kept solids and oily contaminants well dispersed, which allowed the water to pass through the filter in less than 35 seconds – a 10-times faster injection rate compared to the blank.
In similar rapid filtration tests comparing the biosurfactant-based additive to a traditional injectivity aid, FloBoost-treated water passed through the filter at a 77% faster injection rate. At equivalent concentrations, the FloBoost biosurfactant-based additives outperformed the incumbent product by more than four times, implying that lower dosage rates can be used for lower treatment costs.
A series of filtration tests conducted in the field mirrored the biosurfactant-based additive’s performance improvements in the lab (Figure 2). A blank fluid sample collected from a SWD well in the Delaware basin took 127 seconds to pass through a Millipore filter. Fluid samples treated with the incumbent chemistry had an average injection rate of 70 seconds, while the biosurfactant-treated samples delivered an average injection rate of only 43 seconds, a nearly 39% improvement.
Field performance
FloBoost was used in a New Mexico SWD well that was injecting 10 – 11 000 BWPD. The injection pressure was 1200 psi. The produced saltwater contained oil, iron, and scale. In previous treatments, acid and surfactants were added to the high-pressure side of the H Pump. No decrease in pressure was observed with any previous treatments. A batch dosage of 250 ppm of FloBoost was used over two days. Within those two days, injection pressure reduced 12% from 1200 psi to 1060. The injection volumes were maintained at 11 000 –12 000 BWPD.
Conclusions
As produced water volumes increase and SWD wells become more difficult to manage, operators will need cost-effective solutions to inject more water without increasing injection pressures. Biosurfactant-based SWD management additives offer a proven solution by achieving maximum injection volumes for a given maximum allowable injection pressure. Reducing injection pressure optimises power usage by injection pumps, and increases operational efficiency while significantly lowering energy costs in the field. With their combined ability to reduce disposal costs while also lowering an SWD facility’s carbon footprint, biosurfactant-based additives are ideally positioned to become the injectivity aid of choice for SWD operations.
References
1. JOHN KEMP, “Water is the biggest output of U.S. oil and gas wells,” Reuters, https://www.reuters.com/article/us-usa-shale-waterkemp/water-is-the-biggest-output-of-u-s-oil-and-gas-wells-kempidUSKCN0J223P20141118
2. KYLIE WRIGHT, et al. “The great saltwater flood in the Permian Basin,” World Oil, July 2022. https://www.worldoil.com/magazine/2022/july-2022/ special-focus-permian-basin-technology-shale-technology/the-greatsaltwater-flood-in-the-permian-basin/
3. ERIN DOUGLAS, “Earthquakes in Texas doubled in 2021. Scientists cite years of oil companies injecting sludgy water underground,” The Texas Tribune, 8 Feb 2022. https://www.texastribune.org/2022/02/08/westtexas-earthquakes-fracking/
Autumn 2022 Oilfield Technology | 51
52 |
he global energy transition and emissions management together constitute a journey. To meet the world’s rising energy needs throughout this journey, energy producers will be presented with many challenges requiring adaptation and innovation. Though alternative forms of energy seem to dominate the thinking around the transition, the oil and gas industry will remain a pioneering leader and vital contributor to our energy needs.
The use of fossil fuels for heating, medicine and other applications dates back to antiquity in the regions around the Caspian, Black, and Aegean seas. However, only in the past century and a half have they served the whole world, not only as a primary means of fuelling everything from gas lighting and heating to transportation and industry, but also as key components in products that define modern living – from soaps and solvents, to plastics and pharmaceuticals.
Today, however, with growing concerns surrounding environmental conservation, carbon emissions, and a warming planet, the expectation is that the oil and gas sector should adopt more sustainable practices and reduce emissions.
TETRA Technologies is an oil and gas services company with a diverse portfolio supporting the energy transition, and the company has made sustainability integral to its business.
Carbon capture to reduce CO 2emissions
TETRA has made agreements with Texas-based CarbonFree, a global carbon capture company with patented technologies that capture carbon dioxide (CO 2 ) and mineralise emissions to yield commercial products. Carbon-Free’s SkyCycleTM is a unique technology that uses calcium chloride in its conversion process.
Lenus King, TETRA Technologies Inc., USA, details several innovations for emissions management in the upstream oil and gas sector.
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TETRA works with calcium chloride chemistry, producing various formulations of the compoundfor use across a wide range of industrial, agricultural, and food and beverage applications. The company is collaborating with CarbonFree to support its calcium chloride needs for the SkyCycle.
Zinc-bromine flow batteries
A crucial component of the energy transition is large-scale energy storage. One type of technology in this regard is the zinc-bromine flow battery, which is typically a large rechargeable battery system with an electrolyte of aqueous, high-purity zinc-bromide-based solution that exploits the reaction between zinc and bromine to store and deliver electric power. Its primary use is large-scale, high-capacity energy storage for solar and wind applications, providing reliability when darkness or low wind conditions interrupt power generation.
The performance and life of zinc-bromine batteries depends on the quality of the electrolyte; impurities of any kind can compromise battery capacity, operation and longevity. Aware of this, TETRA leveraged its processes and expertise in chemistry to develop TETRA PureFlow® ultra-pure zinc bromide – a pure compound derived from elemental zinc and bromine, for use in zinc-bromine batteries. The company is now supplying
TETRA PureFlow to battery manufacturers, and can also produce aqueous zinc-bromide electrolyte to customer specifications.
Zinc-bromine battery technology is a greener alternative to the costlier lithium-ion battery. Its water-based electrolyte makes it less prone to overheating and fire than its lithium-ion cousin. Additionally, unlike the solvent-based electrolyte of lithium batteries, which can become a hazardous waste when the battery reaches its end of useful life, a zinc-bromine electrolyte can be recycled for reuse in either another batch of electrolyte or in an oil and gas operation, reducing the need for disposal. In other words, zinc-bromine technology yields a greener battery and a renewable form of energy.
Calcium bromide mercury removal
Although mercury is a vital element in medicine, dentistry, electronics, and measuring instruments, it is also a pollutant. Gaseous mercury is released when coal is burned, and coal remains a common fuel for power plants around the world. If mercury finds its way into aqueous ecosystems – ponds, lakes, streams, rivers, seas – it can form the highly-toxic methylmercury, which can then be absorbed by plankton and thus enter the food chain. This toxin adversely affects the nervous, immune, and enzyme systems of animals – including humans.
Both bromine and calcium chloride play a crucial role in eliminating the release of mercury emissions into the environment. Calcium bromide and calcium chloride are very effective at oxidising gaseous elemental mercury, which at combustion temperatures is otherwise difficult to capture. Using the bromine or calcium chloride compounds in pollution abatement equipment greatly enhances the removal of mercury from the flue gas of coal-fired power plants, helping to prevent mercury emissions. TETRA manufactures both calcium bromide and calcium chloride in both liquid and solid form.
Environmentally-friendly completion fluids
The deeper one drills, the higher the pressure grows. As offshore development entails increasingly deeper wells, in many cases the density of completion fluids needs to be increased to control reservoir pressure. In the past, this was accomplished by using zinc-based brines, but because zinc is classified as a marine pollutant in many parts of the world, expanding offshore activity led to environmental measures that severely restricted the use of these brines in the Gulf of Mexico, and outright banned them in the North Sea. Operators switched to cesium formate brines for the requisite densities, but due to the limited availability of cesium, the cost of these brines became prohibitive for applications requiring large volumes.
Operators needed an affordable, dense, environmentally-friendly brine made from readily-available ingredients, capable of withstanding harsh downhole conditions and the deepwater cold (e.g. not crystalising). To meet this demand, TETRA’s scientists developed TETRA CS Neptune® completion fluid – a high-density, zinc-free, formate-free, solids-free fluid. After several applications, the brand expanded to a suite of fluids – high-density, extra-high-density, monovalent, divalent – that are all customised specifically for each application. They are compatible with elastomers, pose low corrosion risk, perform at low temperatures and high pressures without crystallisation, and can be formulated as low-solids reservoir drill-in fluids.
Additionally, these fluids are cost-effective and environmentally-friendly, which render them feasible
54 | Oilfield Technology Autumn 2022
Figure 1. TETRA’s ultra-pure zinc bromide used in zinc-bromine batteries.
Figure 2. Steel lay-flat hose being deployed using TETRA’s rapid deployment and retrieval system.
alternatives for use in the Gulf of Mexico, the North Sea, and the South Atlantic Ocean.
A greener marine cleanout
As with completion fluid chemistry, wellbore cleanout systems have become more environmentally-friendly. These systems are used ahead of the completion phase to displace the solids-laden drilling fluid and leave the wellbore clean, water-wet and, crucially, free of solids. The presence of solids during completion can lead to the cracking and corrosion of metal tubing and, worst of all, damage the geological formation, which would diminish production.
In the past, a typical deepwater displacement of synthetic-based mud entailed a spacer-train of chemicals, and was then (if an indirect displacement) followed by large volumes of seawater, and subsequently the completion fluid. A direct displacement omits the middle step involving sea water. Either way, the use of harsh chemicals was unsustainable.
TETRA set out to develop a greener direct displacement system using natural, non-toxic, bio-based ingredients that would also be highly effective at removing the drilling mud and yielding a clean wellbore for the completion phase. The result of the company’s research and development yielded the TETRA Advanced Displacement System (TADSTM) – a greener alternative with high efficacy at low dosage, without harsh chemicals, that efficiently displaces synthetic-based and oil-based drilling muds.
Reducing oil and grease contaminants
When environmentally-benign completion fluids such as calcium chloride are not reclaimed for later reuse, they can be discharged into the sea (provided that they are not contaminated with oil and grease). TETRA developed its TETRA OilFix™ filtration service for such cases. The two-step service first entails the application of TETRA O-Lok CTM to remove oil and grease during diatomaceous-earth filtration. It then demands the use of a portable infrared spectrophotometer to determine oil and grease levels before and after filtration. Highlighting the service’s effectiveness is a case in Ghana.
Case study: Ghana
The operator’s deepwater operations were plagued with contamination of the completion fluids by the oil-based drilling mud. Transitioning from calcium chloride completion fluid to sodium bromide, the company sought a means to reduce contamination of the new fluid so that it could be reclaimed for reuse and of the previous fluid so it could be safely discharged into the ocean. Filtering some 36 300 bbl of fluid, the treatment reduced oil and grease contaminants by an average of 82.4%, with a peak of 86%, rendering the calcium chloride fluid environmentally-safe for discharge, and saving the customer time and money.
A better bromide and fluid reclamation
Bromine is widely used in oil and gas applications, specifically to formulate calcium bromide, sodium bromide, and zinc bromide – clear brine fluids used in the completion phase of a well’s development. TETRA produces bromide fluids at its plant in West Memphis, Arkansas, US, and distributes them through global service centres.
The company develops processes for manufacturing bromide-based brines, including one for enabling the use of elemental bromine, and another for enabling the use of elemental
zinc in the manufacturing process. Using these processes to produce zinc bromide – instead of the more common method with bromic acid and zinc oxide – the company produces a pure product using less energy and producing fewer emissions. TETRA also reclaims bromide brines used in completion and workover applications for later reuse.
For some years now, zinc has been labelled a priority pollutant, with its use in offshore operations either banned or severely restricted. TETRA has a process for fluid reclamation that is more efficient than a number of methods that produce large volumes of waste. Additionally, any zinc bromide that cannot be reclaimed and treated at a service centre for reuse can be sent back to the West Memphis plant for remanufacture, thereby reducing the need for disposal.
Water transfer and treatment
Hydraulic fracturing has drasticly changed the oil and gas industry. Using water and sand-proppant to crack the formation has enhanced production by an order of magnitude. However, not only is the use of increasingly-scarce freshwater for fracking unsustainable (especially in desert regions and during periods of prolonged drought), but fracking also yields high levels of produced water, which is compatible with the reservoir fluids but cannot be used for fracking – in most cases.
Operators are now turning to recycling produced water for frac use. With treatment facilities centrally positioned to serve multiple frac sites, the water is transferred using pumps and piping, which is more efficient and greener than trucking it back and forth. However, a pipeline spanning up to three miles with dozens of pipe joints can be prone to leaking, and delivering reams of pipe sections requires an undesirable number of truck trips.
TETRA engineers designed a lay-flat hose – a double-jacketed, high-pressure, flexible hose for water transfer. With longer sections and positive-lock couplings, the system reduces the risk of leaks. Moreover, the hose is rapidly put in place and later removed using the company’s rapid deployment and retrieval system, which reduces the number of trucks required for piping operations. This also results in lower emissions.
Automating water management
Automating the transfer, treatment, storage and delivery of water is infinitely more efficient than conducting these operations manually. Automation reduces onsite personnel and the associated safety risks, and leverages advanced computing technology to ensure precision in treatment, pressure, pump performance, and storage levels, which lessens environmental risks. Moreover, an automated system enables users to control and monitor operations from afar, and generate metrics and data that can then be used to fine tune processes.
The TETRA BlueLinxTM automated control system’s nerve centre is a cloud-based dashboard connected by cellular or satellite link to the field equipment sensors, providing real-time access to readings of inlet and outlet pressures, fluid composition, water conductivity, storage levels, pump-engine operation, and equipment status and performance.
The efficiency of the TETRA BlueLinx system also reduces emissions, firstly, by reducing personnel trips to and from the site, and secondly, by precisely controlling pump engines for maximum efficiency and minimal fuel needs. The system also reduces the potential for human error and environmental spills.
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omplex geology requires innovative solutions to optimise well placement and maximise production. Deposition of a reservoir unit can result in a complex distribution of productive and nonproductive formations, which can be further deformed by later erosional and tectonic events. The ability to intersect as much productive reservoir as possible requires early identification of formation and fluid boundaries to allow for corrections to the well path while limiting tortuosity. Reactive geosteering logging-while-drilling (LWD) technologies require wells to intersect a unit to identify
their lithology. In a simple three-layer case, this can result in steering a well by oscillating between the top and bottom boundaries. In complex cases where formations may pinch out, are subjected to deformation, or show lateral lithological variation, reactive geosteering can result in multiple exits from the target zone and a tortuous well path that will increase drag on the completion assembly.
Azimuthally sensitive electromagnetic (EM) LWD tools are deployed to provide a more proactive approach to the well placement operation. The technology investigates the
Dr. Alban Duriez, and Dr. Nigel Clegg, Halliburton, USA & UK, explain how azimuthally sensitive electromagnetic LWD tools can be deployed as part of a proactive approach to well placement operations.
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resistivity properties of formations away from the wellbore. Combined with advanced processing, the measurements resolve the location of the bed boundaries around the borehole and anticipate trajectory adjustments to remain in the targeted layer. Ultra-deep EM tools, such as the EarthStar® ultra-deep resistivity service, have shown the advantages of this approach in thick reservoirs. However, many wells require a more focused approach that provides early warning of resistivity and can map very thin units to understand multiple layers or thinner target zones in more detail.
With the release of the StrataStar TM deep azimuthal resistivity service, Halliburton has added another technology to its iStar TM intelligent logging and drilling platform. The service expands the portfolio of LWD solutions to precisely place wells where
they most benefit the operators to maximise their asset value.
The StrataStar service provides an early warning of changes in resistivity and the ability to map thin units, which allows proactive geosteering in difficult environments where a strategic understanding of a well’s position can be refined to maximise reservoir exposure.
Multiple simultaneous measurements
The proactive element of deploying an EM tool is the result of EM energy penetrating the formation away from the wellbore. Put simply, this is a function of the distance between transmitter and reciever antenna, the frequency of transmission, and formation resistivities. Higher depths of investigation can be achieved with longer spacings and lower frequencies. Combining a long spacing deep transmitter with shallow spacing transmitters allows the tool to provide both the bigger picture of the reservoir for early warnings and the higher detail to provide a better understanding of the reservoir (Figure 1).
The ability to optimise how the formation is investigated for depth and detail makes the service a useful component for well placement operations in complex wells.
The service uses accurate deep azimuthal resistivity measurements and an inversion algorithm to provide a fast, real-time visualisation of the geology up to 30 ft (9 m) away from the wellbore (Figure 2). Representing the position of formation and fluid boundaries in this way provides an easy-to-understand picture of the position of the well and simplifies decision making. Its ability to delineate the positions, thicknesses and resistivities of the surrounding rock and fluid layers while drilling allows geosteering experts to precisely
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Figure 1. Illustration of the deep azimuthal resistivity service tool model.
Figure 2. Illustration of the deep azimuthal resistivity service downhole.
Figure 3. 1D inversion canvas of the complete lateral section showing the distribution of high (red) and low (blue) resistivity 25 ft (± 9 m) above and below the wellbore. Resistivity colour scale is in ohm-metres, and the vertical scale is exaggerated with a horizontal to vertical distance ratio of 10.
place the borehole in the reservoir, even in very thin and demanding formations.
Uninterrupted contact with the productive zone is increased, which simplifies the completion design and leads to higher production.
Evaluating reserves with accuracy
In addition to accurate well placement, understanding the reservoir in detail is vital for evaluating its quality. The StrataStar service provides high-accuracy formation insight, driving advanced petrophysical analyses of a reservoir. The tool provides resistivity at four different spacings, using two frequencies that are all corrected for borehole effect. The service also measures the formation anisotropy, and its dip and azimuth at any well angle through its antenna design. Real-time access to the apparent resistivity and Rv and Rh in a relatively undisturbed environment enables a more accurate calculation of the hydrocarbons in place.
Figure 4. Overlay of the high-definition 1D inversion canvas of the horizontal injector-producer pair. The vertical scale is exaggerated with a horizontal to vertical distance ratio of 20.
The service uses highly sensitive resistivity antennas mounted on a tool design that enables the deepest single-collar resistivity reading without adding length to the bottom hole assembly. With this approach, the deep azimuthal resistivity service provides better data interpretation, widens the volume investigated, and increases the amount of information collected in real time to precisely steer wells where they will most benefit operators.
The challenges of field deployment in the face of the pandemic
First deployed in North America as a prototype, the service demonstrated its high-resolution mapping capability over a 10 000 ft long section (Figure 3). Its resistivity measurements were also compared with another deep resistivity service in the same run and validated the accuracy and the quality of the data for petrophysical analysis. The complex environment (Figure 3) demonstrates the need for high-accuracy geosteering and geomapping solutions as the target units show considerable variability in thickness and resistivity. It is not possible to track a single boundary for the length of the entire well: units pinch out, are dislocated by faults and tectonic deformation, and overall, the formation shows lateral variability. Attempting optimal well placement in this environment with reactive geosteering methods would be extremely difficult if not impossible. Displaying the resistivity distribution in the simple format of an inversion canvas shows the position of the well as it is being drilled, the position of the units of interest and how the well path could be changed to maintain its position within the desired zone. During well placement, successful operations are driven by good communications. Presenting data in this way provides a depiction of the reservoir that all the stakeholders can understand from the subsurface team to the drillers, allowing for better decisions to be made quickly.
Deep EM LWD tools can be applied to an array of subsurface environments. Provided there is a resistivity contrast to detect, the tools can be deployed to identify it. For example, in Canada the StrataStar service endurance was later tested in
steam-assisted-gravity drainage wells, where wells are drilled very quickly in an abrasive sand. The service was used on five consecutive wells reliably. In this field, the resistivity mapping sheds a new light on the heavy oil distribution and the locations of natural production barriers. When steam is injected into the formation to mobilise the oil in place, these production barriers can limit the penetration of the steam. Understanding their distribution allows optimisation of the steam injection and production strategy. In this scenario, mapping the units is as critical as changing the well position during drilling.
Deep azimuthal resistivity data acquired in a pair of injector–producer wells showed a perfect match of the resistivity maps, delivering a complete picture of the heavy oil distribution in the reservoir (Figure 4). This provides critical information to the operator and is also a valuable validation of new technology. Two parallel wells in which inversions are run independently on overlap provides an opportunity to test the repeatability of the inversion. The results show continuity of the steam barriers across the two inversions when they are superimposed. This allows the operator to adapt the completion design to maximise production and save on steam injection costs.
Preparation is key
With tools capable of working in multiple diverse geological environments, preparation is important to the success of any operation. Extensive pre-well modelling is conducted before the commencement of any operation to both identify how the tool will respond in any given situation and how to use it best. Offset data is used to generate multiple scenarios anticipated during the operation to give operators the confidence in new technology and enable them to become familiar with the data, how it will be displayed, and how best to use it. As a result, well placement decisions become easier, and operations more successful.
Integrated approach to well placement
As these tools are deployed in multiple geographies, the challenges can be significant. The ability to identify early warnings, combined with an understanding of the subsurface geology and the high level of detail in thin units, provides improved reservoir understanding and accelerated educated decisions while drilling. The StrataStar service can be combined with other LWD technologies, such as gamma rays, density/neutron, and pressure in order to data resolve various reservoir complexities.
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Eirik Renli, Fishbones, Norway, discusses how multi-lateral technology can help to deliver hydrocarbon recovery in a sustainable way.
obody operating within the oil and gas sector will be complacent about the challenges that the industry currently faces. While the sector has continued to respond to the requirements presented by the necessary energy transition, external global events have thrust the topic of oil and gas supply and demand to the front of societal and political consciousness.
All of those who work within the sector must play a part in meeting the world’s energy requirements, however this must be done with a mindful approach that is not at odds with the ongoing transition.
Reservoir stimulation has long been seen as the preferred solution to increasing oil production from underperforming wells. With demand for energy increasing within the current geopolitical climate, there is a growing need to consider its
ability to support new wells in order to deliver enhanced, efficient recovery.
With this backdrop in mind, Fishbones has committed to reducing operational risk, lowering associated project costs, and guaranteeing deep reservoir connectivity. This is an approach that has resulted in the delivery of projects from the North Sea to the Middle East. It is this approach, allied with the strong desire to undertake recovery in a more sustainable way, that will help ensure that the industry continues to meet sector demands – but in a way that supports its ambitious net zero targets.
Reservoir stimulation must go beyond improved oil recovery Fishbones specialises in reservoir stimulation and improved oil recovery solutions. The company’s technology helps to increase
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Within the current climate, it is more important than ever that operators are provided with cost-effective and efficient production methods.
Multi-lateral technology can increase recoverable reserves
An approach that the industry should consider is centred around the use of multi-lateral technology. Whilst market alternatives such as matrix or bull-head stimulation deliver positive results, their use may not always be suitable across all types of reservoir. Elsewhere, hydraulic fracturing could easily deliver the required stimulation, but achieving consistent results with this method will always prove challenging. Additionally, the process also requires significant resources, placing increased demands on health, safety and environment (HSE) requirements.
The company’s jetting and drilling technology helps operators to overcome these stimulation challenges, by enabling the connection between the well and the reservoir through an open hole liner completion. Several laterals are then created simultaneously in a short pumping operation by means of either drilling or jetting, depending on the type of formation presented.
The precisely-distributed laterals can bypass any damaged zone around the wellbore, penetrate low permeability, connect to natural fractures, and increase the effect of a wellbore’s radius.
Sustainable operations and cost-effective production
When multi-lateral technology is used, the reservoir liner string is run as normal, with drilling subs spaced out at regular intervals along its length. Once securely in place, small-diameter laterals equipped with turbines and drill bits will simultaneously drill to penetrate the surrounding reservoir. It is this that helps to ensure that activity can be undertaken efficiently and without costly delays. With this drilling procedure, a penetration rate of 10.8 m (or 35 ft) of the surrounding reservoir can be achieved.
Alternatively, Fishbones' jetting technology system sees four 12 m long diameter needles penetrate the surrounding geology, creating channels that can connect to what would otherwise be inaccessible hydrocarbon reserves. The subs that are run as normal on the reservoir liner string then combine with the Backbone Open Hole Anchors and activation shoe. At full extension, achievable penetration is typically 12 m,
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production rates in deviated, horizontal, and challenging vertical open hole wells. The entire market must now look at ways to increase recovery and maximise the valuable assets available.
Figure 1. Fishbones’ technology can support hydrocarbon recovery in challenging wells, with reduced risk and environmental impact.
Figure 2. Small-diameter laterals equipped with turbines and drill bits simultaneously drill to penetrate the reservoir.
or 40 ft. The number of laterals deployed is completely tailored to the needs of a well, with four laterals deployed per sub.
The combination of these components helps ensure that all jetting system activity can be installed and maintained while downhole. With the ability to reduce the total well requirements of a given reservoir, while increasing recoverable reserves, multi-lateral technology has the capacity to support ongoing field development activity in the sector.
As sustainable and cost-effective production methods are becoming increasingly important, this technology is providing a viable route for operators to maximise existing assets while minimising what are often costlier, more environmentally-damaging processes.
Accessing complex wells and reservoirs
Within the context of the Norwegian sector, most operators would accept that there is no such thing as ‘easy to access’ oil anymore. This, in turn, has led to changing requirements regarding reservoir stimulation to support recovery from challenging, complex wells, and from harder-to-reach reservoirs. As the recoverable oil below the sub-surface now sits within these challenging reservoirs, the development of new technology to support production has surged.
Jetting and drilling technology have gone a long way to help operators to overcome these new challenges. Tailor-made solutions can help to deliver enhanced production rates and deep reservoir connectivity. Both deliver the solution to support operators in accessing challenging wells and reservoirs, with a reduced environmental impact.
Meeting environmental challenges
This article has discussed the energy transition and its rightful place as one of the most significant issues facing the industry. It must be reiterated, however, that the duty and responsibility must sit upon all within the industry to deliver more efficient solutions for recovery.
While Fishbones’ technology is helping control and accuracy in stimulation, it is doing so more sustainably. This has been demonstrated, and the findings that evaluated the relative carbon footprint between the company’s stimulation options and alternative conventional completion techniques were published in 2021. This showed an 88% fall in emissions for the jetting solution, and a 95% reduction for drilling activity.
The independent study, which was undertaken by THREE60 Energy, found that carbon dioxide (CO 2 ) emissions for Fishbones’ stimulation activity was lower than some practices. The report calculated that CO 2 emissions generated by the jetting solution stood at 6.7 t per completion, compared to 53.3 t generated by acid fracturing. Similarly, the calculated drilling CO 2 emissions stood at 35.4 t per completion, with propped fracturing techniques generating 651 t of emissions by comparison.
Those in the industry must work together
The energy industry has always been driven forward by close collaboration, the sharing of ideas, and by working together to
deliver results. The mercurial nature of the industry has seen it face many economic, environmental, and societal headwinds and challenges, but the storm has been weathered by working together. This collaborative approach will prove to be more important than ever during the coming months, as the industry responds to ongoing demands for sustainable operations and cost-effective production methods.
Working in close partnership with others is key to success, and the industry’s mission should be to unlock the full value from reservoirs and wells. Early and close partnerships working with customers have always been an integral means of supporting this ambition. This approach will ensure the continuation of the provision of a viable route to maximising resources and assets, in a way that is less environmentally-damaging than market alternatives. Reservoir stimulation has always been a vital element of a successful oil and gas sector, and will continue to be.
Edvard Grieg
Edvard Grieg is a field in the Utsira High area in the central North Sea, 35 km south of the Grane and Balder fields. The water depth is 110 m. Parts of the reservoir on Edvard Grieg consist of conglomerates, which is a hard and tight reservoir type.
In 2021, Fishbones and Lundin Energy Norway worked together on the completion of a new production well on the Edvard Grieg field. The Fishbones technology, which was used on the well, increased the effective drainage radius around the production wells by drilling several small holes out from the main well. This enabled the production of increased oil within the relatively tight reservoir rocks.
The wells A-17 and A-16 were both completed using Fishbones’ stimulation technology. The ‘pinholes’ drilled out from the A-17 well on Edvard Grieg were around 9 m long, and were drilled out in groups of three from drilling subs. A total of 53 drilling subs were installed – the most ever used in a single well.
Well A-17 achieved excellent production results – ten times better productivity than Lundin’s original prognosis, representing operational success for the technology.
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Figure 3. The jetting technology creates channels that can connect to what would otherwise be inaccessible hydrocarbon reserves.
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