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JPT Special Publications Editor
Industry Works To Balance Risk and Reward of Digitizing Safety
Wilson, Adam (JPT Special Publications Editor)
The oil and gas industry has picked up on the benefits of digitization and artificial intelligence (AI) in its day-to-day activities, and the health, safety, and environment (HSE) sector is no exception. While AI brings clear benefits, the risks that come with those benefits remain unclear. While touting the advances of technology in HSE at SPE’s Virtual Annual Technical Conference and Exhibition (ATCE), Olav Skar, director of health, safety, security, and wells at the International Association of Oil and Gas Producers (IOGP), said, “I also see risks, and I remain concerned that we do not truly understand them.” Skar spoke at the ATCE on a panel that included Mohamed Kermoud, Schlumberger’s global vice president for HSE, and Philippe Herve, the vice president of energy solutions at Spark-Cognition. The panel was moderated by Josh Etkind, Shell’s Gulf of Mexico digital transformation manager. “A lot of power is in the technology,” Herve said. “The technology is beautiful. How we as humans are going to apply it, we need to think about it. We are thinking about all of the good things that the technology is bringing to humanity. Let’s keep it that way and remove all of the applications of artificial intelligence technology that may not be well perceived or beneficial to anybody.” An early target for digitization in oil and gas, driving has been the most dangerous HSE activity for employees. The IOGP claims that land-transportation-related incidents historically have been the largest cause of fatalities for its member companies. Since 2000, such incidents have accounted for 22% of all work-related fatalities reported by IOGP members. Schlumberger’s approach to driving safety was outlined in a paper presented at the 2020 SPE International Conference and Exhibition on Health, Safety, Environment, and Sustainability, a synopsis of which appeared in the August 2020 issue of JPT (http://go.spe.org/_01104-1542r). Schlumberger’s approach to improving driver safety includes an advanced driver-assistance system that alerts drivers of maximum speed limits, lane departures, and the proximity of pedestrians and other vehicles. The goal of the system is to effect good driver behavior. “If you analyze all the data, all the incidents, you find that behavior is always behind it,” Schlumberger’s Kermoud said. “People are trying to save time, to save the day. … The rules are generally perfect, but the behavior is something that we absolutely need to make sure that we impact one way or the other. And using technology will help us.”
- North America > United States (0.25)
- North America > Mexico (0.25)
Automated Operations and Wired Drillpipe Benefit Arctic Drilling
Wilson, Adam (JPT Special Publications Editor)
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 191574, “Delivering Drilling Automation II: Novel Automation Platform and Wired Drillpipe Deployed on Arctic Drilling Operations,” by Riaz Israel, Doug McCrae, Nathan Sperry, Brad Gorham, Jacob Thompson, and Kyle Raese, BP, and Steven Pink and Andrew Coit, SPE, NOV, prepared for the 2018 SPE Annual Technical Conference and Exhibition, Dallas, 24–26 September. The paper has not been peer reviewed. This paper presents a case history of drilling automation system pilot deployment, including the use of wired drillpipe, on an Arctic drilling operation. Two major aspects of technology were introduced during this pilot, the first being a drilling automation software platform that allowed secure access to the rig’s drilling control system. The second component was a wired drillstring, which provides high-speed delivery of downhole data from a series of distributed downhole sensors. Introduction In an effort to enhance the safety of its operations, improve well construction efficiency, and leverage the potential opportunities presented by digitalization of drilling, the operator has initiated a Remote Operations and Intelligent Automation Project. The project involved the deployment of an automation operating system (AOS) on top of an existing drilling control system. The AOS provides the ability for secure, programmatic control of the rig’s major drilling hardware through the use of software. The software interface allows for custom configuration of several routine drilling activities for automated execution. The project also evaluated the latest version of the service company’s wired drillpipe (WDP). At the time of writing, the project has delivered eight wells, with various combinations of the technology implemented. The overall objectives of the project were to evaluate The readiness of the AOS for wider deployment The reliability of the latest version of WDP The maturity of the AOS drilling applications The effectiveness of this technology in reducing well costs For each well, key performance indicators (KPIs) were defined that aligned with the project-level KPIs and are dependent on the specific aspect of the technology being used on that well. Field Description The giant Prudhoe Bay field, on the North Slope of Alaska on the edge of the Arctic Circle, was discovered in 1968 with an initial estimate of 22 billion to 25 billion bbl of oil in place and has been in production since June 1977. Since the field began production, it has generated more than 12.5 billion bbl of oil, making it the most productive US oil field. The field has been a proving ground for advanced drilling techniques, including multilateral and coiled tubing, now used in oil fields around the globe. Production from Prudhoe Bay is supported by ongoing drilling activity. Technology Description An overview of the automation technology is presented in Fig. 1.
- North America > United States > Alaska > North Slope Basin > Prudhoe Bay Field (0.99)
- Asia > Middle East > UAE > Abu Dhabi > Arabian Gulf > Rub' al Khali Basin > Ghasha Concession > Umm Shaif and Nasr Block > Umm Shaif and Nasr Field > Umm Shaif Field > Arab Formation (0.99)
Analysis Quality Determines Value of Diagnostic Fracture Injection Tests
Wilson, Adam (JPT Special Publications Editor)
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 191458, “Good Tests Cost Money, Bad Tests Cost More: A Critical Review of DFIT and Analysis Gone Wrong,” by R.V. Hawkes, SPE, Trican Well Service; R. Bachman, SPE, CGG; K. Nicholson, Perpetual Energy; D.D. Cramer, SPE, ConocoPhillips; and S.T. Chipperfield, SPE, Santos, prepared for the 2018 SPE International Hydraulic Fracturing Technology Conference and Exhibition, Muscat, Oman, 16–18 October. The paper has not been peer reviewed. Diagnostic fracture injection tests (DFITs) incur direct and indirect costs resulting from the tests themselves and the extended time required for the pressure falloff, which delays the completion of the well. The benefits, therefore, must outweigh the costs if the test is to be justified. These tests are performed regularly around the world because a DFIT is one of only a few processes that can help quantify both geomechanical properties and reservoir-performance drivers within the same test. Introduction Operators and service providers commonly experience problems with DFIT execution and analysis despite efforts to reduce errors and inconsistencies. Before any field execution or analysis, the objectives of a DFIT must be considered. Historically, DFITs were performed predominantly for the purpose of designing better full-scale hydraulic-fracture treatments with early-time measurements of initial shut-in pressure, leakoff coefficient, and fracture closure having priority over reservoir parameters such as permeability and pore pressure. Increasingly, practitioners are using DFITs to measure reservoir parameters such as initial pressure and permeability. While, in many cases, these parameters may be obtained from a single successful test, other situations have time constraints or rock and reservoir properties that constrain operations to a point where priorities must be set. While leakoff and closure values are determined early in the DFIT shut-in period, reservoir pressure and permeability are derived from late-time measurements that may require longer falloff times. The complete paper presents cases encountered in which test procedures/operations or incorrect analysis misled engineers. Cases presented are Several Canadian Duvernay shale wells illustrating the importance of multiple tests and the use of gradients to understand fracture orientation and possible complexity. A well where the initial DFIT had an injection rate that was too low combined with operational issues. A second test on the same interval yielded better results. A Canadian Montney well where rock/fluid interactions led to a false radial-flow signature. Two subnormally pressured Canadian oil wells where surface falloff pressure dropped to a vacuum (i.e., falling liquid level), causing late-time effects that were not reservoir related. The authors present a work flow to determine reservoir pressure in this situation. An Australian naturally fractured gas well showing the importance of sufficient falloff time. A proper DFIT may be critical for assessing the geomechanical and reservoir properties of unconventional reservoirs. However, simple guidelines such as wellbore conditioning, the understanding of pressure anomalies resulting from wells going on vacuum, and the importance of flow-regime identification are often overlooked, leading to poor results. Having access to numerous high-quality data sets from various international oil and gas operators provides insight to establishing some useful guidelines that are applicable anywhere in the world.
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
After-Closure Analysis of DFITs Drives Design of Hydraulic-Fracturing Programs
Wilson, Adam (JPT Special Publications Editor)
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE-191437-18IHFT-MS, “ACA Practical Considerations: When Is It Accurate and How Should It Be Used To Improve Reservoir Stimulation,” by O.A. Ishteiwy, SPE, M. Jaboob, and G. Turk, BP; S. Dwi-Kurniadi, SPE, Schlumberger; A. Al-Shueili, SPE, A. Al-Manji, and P. Smith, BP, prepared for the 2018 SPE International Hydraulic Fracturing Technology Conference and Exhibition, Muscat, Oman, 16–18 October. The paper has not been peer reviewed. The use of diagnostic fracture injection tests (DFITs) for prefracture investigation has become routine in the oil field, particularly for understanding reservoir properties and subsequently optimizing hydraulic-fracture design. A key component of an effective DFIT is an after-closure analysis (ACA) to assess the transmissibility of the formation and allow for effective design. This paper describes a DFIT-analysis program and the suitability of the results from ACAs for use in hydraulic-fracture design. Introduction The Khazzan field is being developed currently and includes multiple gas-bearing formations. The primary development reservoir is the Barik sandstone, which is characterized by permeabilities on the order of 0.1 to 1 md. An additional reservoir under development is the Amin formation, which lies deeper than the Barik and is perhaps more unconventional in nature, with estimated permeabilities an order of magnitude lower than the Barik formation. Both reservoirs require hydraulic fracturing to produce at economically attractive rates and, as such, carry the same sort of challenges to reservoir understanding inherent to all unconventional plays. This was recognized in advance of the appraisal program, and an approach was taken to address these challenges in a more-holistic fashion, encompassing a full suite of data gathering, including surveillance and well testing. One of the key tools used was DFIT along with associated ACA of the decline to determine reservoir properties. During the appraisal phase, significant rigor was aimed at ensuring high-quality data would be recorded and that an appropriate amount of time would be allocated to monitoring pressure declines to enable valid interpretations. This resulted in the ability to draw a good correlation between data gathered from the ACA operations and data collected from post-fracturing well-test data. Methods and Process Stimulation and Testing Sequence. The approach taken to stimulate and test the wells in Khazzan was to use a dedicated well-test unit. The overall sequence was as follows: Rig up well-test package Displace kill fluid and clean out with coiled tubing Perforate the target interval Rig up a tree-saver Perform DFIT and monitor pressure decline Perform main fracturing Establish post-main-fracturing-treatment pressure-decline period for fracture closure Rig down the tree-saver Clean out underdisplaced proppant with coiled tubing Flow the well back for cleanup and testing Perform a drift run with slickline to confirm hold-up depth Rig down equipment and handover well to operations
- Asia > Middle East > Oman > Muscat Governorate > Muscat (0.25)
- Asia > Middle East > Oman > Central Oman (0.25)
- Asia > Middle East > Oman > Ad Dhahirah Governorate (0.25)
- Asia > Middle East > Oman > Central Oman > Barik Formation (0.99)
- Asia > Middle East > Oman > Ad Dhahirah Governorate > Arabian Basin > Rub' al-Khali Basin > Block 61 EPSA > Block 61 > Khazzan-Makarem Field > Khazzan Field > Miqrat Formation (0.99)
- Asia > Middle East > Oman > Ad Dhahirah Governorate > Arabian Basin > Rub' al-Khali Basin > Block 61 EPSA > Block 61 > Khazzan-Makarem Field > Khazzan Field > Buah Formation (0.99)
- (6 more...)
Wireless Downhole Gauges Help Maximize Value of Appraisal Test in Abandoned Well
Wilson, Adam (JPT Special Publications Editor)
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 192053, “Maximizing Value of an Appraisal DST: Recording a 10,000-Hour Buildup in an Abandoned Well Using Wireless Downhole Gauges,” by Stuart Walters, SPE, Gavin Ward, and Mike Cullingford, SPE, Chevron, prepared for the 2018 SPE Asia Pacific Oil and Gas Conference and Exhibition, Brisbane, Australia, 23–25 October. The paper has not been peer reviewed. This paper describes the acquisition and interpretation of long-term pressure-buildup data in a plugged and abandoned deepwater appraisal well. To accomplish the test objectives at an acceptable cost, a novel combination of well testing, wireless-gauge technology, and material-balance techniques was used to allow the collection and interpretation of reservoir-pressure data over a planned period of 6 to 15 months following the well test. The final buildup duration was 428 days (14 months). Introduction Three interpretation methods of increasing complexity were used to provide insights into the reservoir. First, material balance was used to produce an estimate of the minimum connected reservoir volume. The advantage of material balance is that it requires very few input assumptions and produces a high-confidence result. Second, analytical models in commercial pressure-transient-analysis software were used to investigate near-wellbore properties and distances to boundaries. Finally, finite-difference-simulation models were used to investigate reservoir properties and heterogeneity throughout the entire tested volume. With increasing model complexity came additional insights into the reservoir properties and architecture but reduced solution uniqueness. A key complication for the interpretation of the recorded pressure data was the potential for gauge drift. This was incorporated into the uncertainty range used in all three interpretation methods. Well-Test Design Analysis of conventional well-test designs (with varying flow rates and buildup periods) showed that the cost of resolving the key uncertainties exceeded the value of information significantly. To justify the appraisal, a way was needed to extend either the flow period or the buildup period without a rig on station and with the well left in a permanently abandoned state. To meet this objective, the potential of wireless-gauge technology to extend the buildup length was evaluated. Two competing wireless technologies were available, acoustic and electromagnetic transmission, both occurring up the tubing/casing. The key differentiator was that acoustic transmission required that cables be run through any cement plugs, which violated the barrier standards for abandoned wells. Accordingly, electromagnetic transmission was selected for the final system. The post-abandonment well concept is shown in Fig. 1. Of note is that the wellhead was not recovered and the top of the 20- and 36-in. casings have not been severed. One critical design feature was the use of redundant gauges (four), repeaters (four), and subsea modems (four) to ensure no single point of failure existed within the wireless system. This also resulted in a narrowing of the gauge-drift and accuracy-uncertainty range as the response of individual gauges was thought to be independently and identically distributed.
Debottlenecking Through Produced-Water Partial Processing Unlocks Production
Wilson, Adam (JPT Special Publications Editor)
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 187109, “Partial Processing: Produced-Water Debottlenecking Unlocks Production on Offshore Thailand MOPU Platform,” by C.H. Rawlins, SPE, eProcess Technologies, prepared for the 2017 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 9–11 October. The paper has not been peer reviewed. An operator in the western Gulf of Thailand installed two water-management partial-processing systems on its mobile offshore production units (MOPUs) to increase oil production. Water removed at the production manifold is treated and transferred directly to the injection system, thus bypassing primary separation, transfer piping, fluid heating, and floating storage facilities. Water debottlenecking increased oil production by 80% and reduced the in-field transfer volume by 62%. Introduction In mature oil basins, the ability to sustain oil production depends on managing an increasing volume of produced water. The partial-processing method seeks bulk (not complete) removal of a throughput-constraining phase from oil and gas production using compact processing equipment. Partial-processing technology normally is installed on facilities that have space or weight constraints, where traditional separation technologies will not fit. Fitting within or around existing process equipment, partial-processing equipment maximizes the capability of an existing facility footprint. The constraining phase may be gas or water, and specific technologies are available to address each. The application detailed in this paper addresses produced-water debottlenecking. Removal of the water constraint unlocks production potential from mature or marginal fields and has been shown to increase hydrocarbon production. Design Stages and Setup For water-constrained systems, the most significant benefit comes from the removal of bulk water as far upstream as possible. High-water-cut wells are combined into a discrete manifold that may handle part or all of the field production. The partial-processing system is on this manifold, upstream from the existing process equipment. Debottlenecking at this point opens capacity in the flow lines, transfer piping, and processing facilities. The partial-processing skid can be installed on unmanned platforms with limited utilities and space and weight constraints. Bulk water removal and treatment may have two or three stages. The first stage, preseparation, involves bulk water removal from the multiphase-flow stream. A specially designed liquid/liquid hydrocyclone (preseparator) removes a bulk portion (60–95%) of the water from the flow stream. Next, the removed bulk water passes to the deoiler hydrocyclone, which operates in a standard produced-water-treating mode. For example, the preseparator will reduce oil content from 10 to 0.2%. The deoiler will take the 2,000-ppm oil down to or near discharge quality (20–50 ppm), depending on oil properties, pressure drop, and temperature. A tertiary treatment stage is optional and is used for difficult separation (e.g., cold fluids with heavy oil) or very stringent disposal requirements (e.g., low oil-in-water levels for enhanced-oil- recovery injection). This stage uses a compact flotation unit (CFU) for both degassing and oil polishing. The CFU removes gas effervescing from solution after the deoiler (which can be 5–10% of the gas void fraction) and uses that gas to float the fine oil droplets.
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Well Operations and Optimization (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)
- Facilities Design, Construction and Operation > Processing Systems and Design > Separation and treating (1.00)
Advanced Electrochemical System Desalts Produced Water, Saves Polymer
Wilson, Adam (JPT Special Publications Editor)
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 190272, “An Advanced Electrochemical System for EOR Produced-Water Desalination and Reduced Polymer Consumption,” by Ben Sparrow, Adrian Ebsary, Derek Mandel, and Malcolm Man, Saltworks Technologies, prepared for the 2018 SPE Improved Oil Recovery Conference, Tulsa, 14–18 April. The paper has not been peer reviewed. This paper presents pilot-testing results and economics from a novel electrochemical desalination technology for enhanced oil recovery (EOR) produced water. The pilot objectives were to (1) economically desalt produced water to improve hydrocarbon recovery and lower polymer consumption costs for chemical-flood EOR; (2) inform full-scale plant development with a field pilot; and (3) optimize prefiltration, chemical consumption, and energy use to realize greater than 20% return on investment through reduced polymer consumption. Background and Pilot Summary An electrodialysis-reversal (EDR) system that requires minimal pretreatment with proprietary hydrocarbon antifouling ion-exchange membranes packaged in rugged skids with advanced process controls was used. The EDR plant can (1) desalt EOR produced water from up to 20 000 mg/L total dissolved solids (TDS) down to 500–5000 mg/L for reinjection and (2) reduce polymer requirements to decrease chemical costs in polymer-flood operations. EDR desalts by use of an electric field; dissolved ions in the produced water are moved across ion-exchange membranes, desalting one stream while concentrating a smaller volume discharge. The TDS in the produced water can be desalted to any concentration that provides optimal performance specific to the reservoir. Depending on the presence of scaling ions, the concentrated stream can achieve TDS concentrations of 80,000–150,000 mg/L, or, in the case of offshore operations, the concentrated stream can be eliminated through a novel process. EOR operators may add polymers and other chemicals to increase viscosity of injected water and enable increased oil recovery. Tests completed for this work proved that EOR polymers present in the produced water that returns to surface do not foul or pass through the EDR membranes, instead remaining in the desalted water for reuse. In fact, some polymers are reactivated in the desalted output, with viscosity increasing by almost double during desalination, thereby enabling some recycling of original polymer. More importantly, results proved that lower TDS of the injected water can result in up to 65% polymer cost savings, which is a major contributor to operating costs. Polymer consumption increases with TDS in order to reach a target viscosity goal; therefore, desalting the injected water can result in net savings if desalination costs are lower than the incremental polymer-consumption savings. This work showed a 30–40% rate of return on investment. To test the theory, an offsite pilot was completed in advance to prepare for onsite work. Produced water up to 20 000 mg/L TDS with oil in water present up to 600 ppm were tested. Prefiltration consisted of proprietary media filtration to remove suspended solids to less than 20-µm particle size. No pretreatment for the oil was required. This is because of the resiliency of the antifouling ion-exchange membranes, EDR stack design to prevent plugging, and intelligent cleaning systems that detect and react to remove fouling or partial plugging before irreversible events occur.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Treatment (0.35)
Technology Focus “Water, water, everywhere, And all the boards did shrink; Water, water, everywhere, Nor any drop to drink.”—Samuel Taylor Coleridge, The Rime of the Ancient Mariner Produced water has been an albatross around the neck of operators for a long time. It gets in the way of production by displacing the target oil, and it is filthy, requiring great expense to treat for reuse or disposal. Efforts to solve these challenges have been extensive and continue to evolve. These efforts can have a strong effect on the profitability of an operation. The authors of paper SPE 187624 claim that the amount of produced water could be in the region of 210 million B/D for every 75 million bbl of oil produced. “Many oil companies could almost be called water companies,” they write. Their paper presents efforts to increase oil production while disposing of produced water by using an inverted electrical submersible pump. These efforts resulted in the disposal of water through the same wellbore, reducing the expense of bringing it to the surface for treatment and of drilling disposal wells. Disposing of the produced water is only one factor that limits the profitability of operations. Treating the water before reuse or disposal also takes a substantial bite out of profits. Paper SPE 190272 examines an economical effort to desalinate produced water with the use of an electrochemical system with a resilient membrane. The membrane’s durability means that pretreatment of the water can be minimal, saving costs. In instances where polymer flooding is used, the membrane allows the polymer to remain in the desalinated water so that it can be used again. The cost savings from polymer reuse can be significant. Production facilities also suffer from the massive quantities of water produced. When produced water moves with the stream through a facility, it takes up precious space that could be used more profitably by oil. Paper SPE 187109 takes a look at one of the ways operators are looking to ease this bottlenecking problem. By partially processing the stream to remove water at the production manifold, more room is made for oil through transfer piping and in primary separation and floating storage facilities. The authors claim this has increased oil production by 80% and reduced the in-field transfer volume by 62%. For more solutions to the persistent problems of produced water, please see the papers listed as recommended additional reading and find more in the OnePetro online library (www.onepetro.org). Recommended additional reading at OnePetro: www.onepetro.org. SPE 187119 Employing Effective Water Treatment in West Texas To Mitigate Surface-Equipment Failures by Sarkis Kakadjian, Keane Group, et al. SPE 190129 Case Studies of an Effective Methodology To Collect Formation Water To Meet Regulatory Requirements for Formation-Water Sampling by V.H. Tran, Chevron, et al. SPE 188400 Successful Field Application of Bulk Water Removal Debottlenecks Declining Songkhla Marginal Offshore Fields, Extending Economic Life by Manuel De La Sota, CEPSA
- North America > United States > Texas (0.57)
- Asia > Thailand > Songkhla > Songkhla (0.26)
Inverted-ESP Completion Boosts Oil Rate While Disposing of Produced Water
Wilson, Adam (JPT Special Publications Editor)
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 187624, “Subsurface Disposal of Produced Water and Simultaneous Increased Oil Production Achieved Within the Same Wellbore Using Inverted ESP—North Kuwait Case Study,” by Shamseldin Z. Elaila, Elred Anthony, Nora H. Al Maqsseed, Mohammad K. Al-Banai, and Sara N. Al-Mutairi, KOC, prepared for the 2017 SPE Kuwait Oil and Gas Show and Conference, Kuwait City, Kuwait, 15–18 October. The paper has not been peer reviewed. This paper aims to provide an introduction to the early management of downhole produced water in strong waterdrive reservoirs using inverted electrical-submersible-pump (ESP) technology. This technology facilitates a method of downhole water disposal within the same wellbore and, therefore, reduces the costs associated with bringing water to the surface or subsurface for treatment. The technique also saves the costs needed for drilling disposal wells. Problems Associated With Produced Water Water produced with petroleum is growing in importance from an industrial and environmental standpoint. In the past, this water was considered to be waste and required disposal. Early on, little attention was paid to the fate of the produced water in the environment. Later, it became clear that possible contamination from produced-water disposal, especially on the surface, needed to be considered. This unwanted water is also a limiting factor in the productive life of the well. Many factors influence the drive for improved water control—loss of hydrocarbon production, environmental effect of disposal, government regulations, and public opinion. The environmental issues and costs related to produced water and its disposal are becoming major considerations for producers. The economic factors of reducing water production far outweigh the cost of typical water-control treatments. Historically, water-control treatments have often failed because of one or more of the following problems: the source of the problem was not properly identified, the wrong treatment was carried out, or the correct treatment was performed improperly. For disposal or injection into reservoir rocks, this water must be processed and treated through a series of time-intensive and costly operations. Suspended solids and oil must be removed to an appropriate degree to reduce oil losses and prevent plugging of the disposal formation. Also, increasingly stringent regulations on the entrained and dissolved oil and other chemicals in the produced water must be met. Economics of Produced Water Except in the case of gas production from coal seams, water-production rates usually start slowly from the initial development of a property. Facility designers may forestall construction and installation of water-handling equipment deliberately at the beginning of a project to reduce initial capital costs. The eventual appearance of water production requires the addition of capital investment and operational expense to handle the growing water rates, which do not generate revenue to offset the cost. The natural tendency for companies is to minimize the immediate expense; as a result, companies often underdesign the equipment or fail to budget properly for operational expenses.
- North America > United States (1.00)
- Asia > Middle East > Kuwait > Al Asimah > Kuwait City (0.24)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Real-Time Data Analytics Allows for Bit-Wear Monitoring and Prediction
Wilson, Adam (JPT Special Publications Editor)
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 189602, “Real-Time Bit-Wear Monitoring and Prediction Using Surface Mechanics Data Analytics: A Step Toward Digitization Through Agile Development,” by Yu Liu, Justin Kibbey, Yanbin Bai, and Xianping Wu, SPE, Shell, prepared for the 2018 IADC/SPE Drilling Technology Conference and Exhibition, Fort Worth, Texas, USA, 6–8 March. The paper has not been peer reviewed. Severe bit damage is an issue in West Texas land drilling because of abrasive sand formation and interbedded hard stringers. Operational performance and rig costs often are affected by bits damaged beyond repair (DBR), low rates of penetration (ROPs) with worn bits, and inefficient decision-making regarding tripping. A real-time data-analytics application is developed that aims to provide information to operators to expedite decision-making. Introduction As bottomhole-assembly (BHA) design and bit selection have become standardized, a historical data set of surface mechanics data and bit records has been accumulated from 40 bit runs. By combining conventional physical modeling of drilling mechanics and supervised machine learning, a hybrid analysis is conducted to separate bit-failure patterns from normal formation transitions and drilling-parameter adjustments. A metric-based algorithm is constructed for real-time monitoring of bit performance and for predicting bit wear. A lightweight web-based framework is used for deployment in real time. A shadow mode trial on three wells in the same pad was conducted and generated satisfactory results. Agile-Development Framework The agile-development framework is an integrated platform for fast technology prototyping, which consists of the following components: The Amazon cloud server is the platform for the application repository, computing-engine execution, and data stream and storage. Most real-time data-analytics applications are delivered as software-as-service, where the algorithm-processed data is stored on the cloud server and pertinent results are delivered to end-users over the web. User interaction with the web application is limited to default viewing options, and other data exchanges such as value inputs are kept to a minimum to reduce complexity. MATLAB and Python are the engines for algorithm development, prototyping, and early-stage deployment. MATLAB is a powerful engineering computing/coding program with strong capability in data management, visualization, and debugging. It provides various toolboxes for signal processing, machine learning, and statistical analysis. Python is an alternative to MATLAB with similar functionality and the advantage of being open source. Codes of data preprocessing, core algorithms, and data stream input/output (I/O) are realized in the MATLAB environment running on the Amazon cloud server. Wellsite Information Transfer Standard Markup Language (WITSML) I/O is the industrial standard for drilling-data stream and management. In this application, surface mechanics drilling data are streamed into MATLAB using a WITSML wrapper. Plotly is a solution for visualization on the web and user interface. Computation results from MATLAB are delivered to a web page by calling Plotly functions within the MATLAB environment.