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The cross-industry development and application of technologies is the epitome of innovation and ingenuity. The more divergent the industries are, the more the unique ways of thinking strike us as remarkable. Technology transfer between the oil and gas industry and other sectors isnโt new. Many examples can be found in medical science, space exploration, and renewable and sustainable technologies. In this JPT issue, the technologies of Oceaneering Space Systems and Impossible Sensing Energy are featured. A case study presented at the 2023 SPE Annual Technical Conference and Exhibition took medical science to a new lowโinto the depths of the Permian Basin for downhole reservoir drainage diagnostics (RDD). The coauthors, a subsurface and wells manager and a chapter manager, surveillance, analysis, and optimization and pilots at Chevron Technology Ventures (CTV), described using genome sequencing for cancer detection and treatment in a successful proof-of-concept (POC) test conducted from 2017 to 2019. Nampetch Yamali and Daniel Emery explained in SPE 215052 how in 2017 CTV was given the task of identifying technology to assess vertical drainage dimensions to estimate drainage volumes from fractured wells. The goal was to minimize interference from offset wells and co-developments to optimize reservoir recovery in unconventional fields. At that time, the technologies and their capabilities were limited. Although subsurface microbial DNA sequencing for upstream assets has found applications in enhanced biocide and corrosion inhibition, reservoir sweet spot indicators, and tracer technology, use of the technique was thought also to have potential in horizontal well development planning via RDD. Learning of a genomic sequencing technique for cancer cell identification in humans at the biology and biochemistry department at the University of Houston, the wheels started turning at CTV with thoughts it could be developed and adopted for RDD. Similarities were seen because RDD uses in-situ subsurface microbial DNA to infer the depths from which fluids drain after fracturing a horizontal well and optimizes well spacing on a pad, especially in stacked reservoirs. The predictive analytics platform mapped the hydrocarbon footprints of geologic subzones by using noninvasive DNA testing tools. The unique DNA markers for RDD were extracted from mud and cuttings from the horizontal and vertical drilling sections. DNA from produced fluids was also collected. The authors wrote, โProduced fluids collected at two-to-four-week intervals at the wellhead are mapped to the RDD framework. They are โlineage tracedโ back to shale and tight rock. Drainage heights and percentage of contribution from these locations is computed adapting DNA sequencing and data analytics pipelines which were developed for lineage tracing cancer cells, breaking off from the primary tumor and metastasizing to distant sites back to the tissue of origin.โ After validating the DNA extractions, CTV conducted a blind test using only the DNA data to determine the landing zones for each of the four wells in the pad. Using clustering methods, the results of the blind test accurately identified all landing zones within an acceptable margin, according to Yamali and Emery. The next step in the trial analyzed the DNA of the produced fluids. โPreliminary results showed drainage height estimates for each horizontal well.โ In 2021, the study continued with an additional four new field trials in the Permian Basin for application of the technique to zonal production identification. The authors wrote, โAlthough the results from the POC were positive, subsurface DNA RDD technology is a novel technique within the oil and gas industry, and advanced applications are still evolving. This combination naturally gives rise to more general skepticism and a need to thoroughly evaluate the technology from operational, economic, and accuracy perspectives.โ The paper describes the ongoing cross-disciplinary work being done by petroleum engineers, geologists, microbiologists, and stratigraphers to fully evaluate this method of RDD. It further details CTVโs wider approach to โaccelerate the innovation life cycle, from pilot stages to widespread adoption at scale,โ emphasizing the need for leadersโ support for nonconventional thinking and approaches. As the close of 2023 approaches, Iโd like to take this opportunity to wish you the best in 2024 on behalf of the JPT Editorial Review Board and the JPT staff. Weโll be kicking off the new year with the commemoration of JPTโs 75th anniversary. Each issue will include an article dedicated to the evolution of technology and industry practices over the seven and a half decades JPT has covered the upstream industry. In January, Trent Jacobs and Stephen Rassenfoss will revisit technological advancements since JPTโs 50th anniversary in 1999. Since then, over 25 million B/D have been added to the global supply thanks in very large part to advancements in drilling, completions, and reservoir technologies. Join us as we explore these along with some predictions made 25 years ago and the surprising realities of where the industry stands today.
- Asia (1.00)
- North America > United States > Texas (0.46)
- North America > United States > New Mexico (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Middle East Government (0.31)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
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- Data Science & Engineering Analytics > Information Management and Systems (1.00)
- Well Drilling > Drilling Operations > Directional drilling (0.97)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (0.87)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (0.87)
PTTEP to Buy Murphy Oilโs Malaysian Business for $2.1 Billion Matt Zborowski, Technology Editor Thailandโs PTT Exploration and Production (PTTEP) is doubling down on Malaysian oil and gas in an effort to broaden its reach in its native South-east Asia. PTTEP has agreed to acquire Murphy Oilโs Malaysian business for $2.1ย billion in an all-cash deal. PTTEP also announced that it was awarded two Malaysian exploration blocks in theย Malaysia 2018 bidย round. The assets to be purchased produced 48,000 BOE/D net to Murphy last year, of which 62% were liquids, and consisted of proved reserves of 468 Bcf of natural gas and 51 million bbl of liquids. The deal includes five petroleum exploration and production projectsโSabah K, SK309 and SK311, Sabah H, SK314A, and SK405Bโin the shallow and deep waters off the Malaysian statesย of Sarawak and Sabah. ย Global Oilfield Services Market Wonโt Recover Until 2025 Trent Jacobs, JPT Digital Editor It has been a tough few years for the worldโs oilfield service sector and, according to a new report, the best of times are on hold for a few more. This is according to Rystad Energy, which says the sector is on pace to capture $920 billion in revenue by 2025. The Norwegian market research firm has highlighted the figure as the high-water mark reached in 2014, a year that ended with crude prices falling by more thanย 40%. โThis will be the longest slump faced by the oilfield service industry since the 1980s, with about $2.3 trillion in revenues lost along the way,โ said Audun Martinsen, Rystad Energyโs head of oilfield service research. Martinsen continued by noting: โOn the bright side, in only 3 yearsโ time, activity levels will be higher than they were in 2014, although the cost cuts achieved in the sector means spending levels will only be 80% of what was seen in that peak year.โ ย ExxonMobil, Chevron Target Nearly 2 Million BOE/D in Permian Production Matt Zborowski, Technology Editor ExxonMobil and Chevron revealed plans that would result in combined production from the US majors of nearly 2 million BOE/D from the Permian Basin of West Texas and southeastern New Mexico by the mid-2020s. ExxonMobil revised upward its Permian production outlook by almost 80% to reach 1 million BOE/D by as early as 2024. The operator said its resource base in the basin totals 10 billion BOE. Chevron expects its output from the basin to rise to 600,000 BOE/D by year-end 2020 before hitting 900,000ย BOE/D by yearend 2023. The company said it has added some 7 billion BOE in Permian resources over the last 2 years. ย Shale Pioneer: Hard Ceiling On Production Growth Coming Trent Jacobs, JPT Digital Editor The central debate today in the US shale business is how long productivity growth will continue. According to one of the most influential voices in the sector, the answer is not much longer. โI am not particularly optimistic that, over the next 5 years, the industry is going to be able to show the year-over-year improvements in well recoveries that weโve seen over the past 10 years,โ said Mark Papa, chief executive officer of private-equity-backed shale producer Centennial Development Resources. Papa said the two biggest factors at play are frac hits, or parent-child well interference, and a shrinking inventory of high-quality drilling locations. ย Shale CEO on Parent-Child Challenge, Well Declines: We Know Matt Zborowski, Technology Editor Much has been made recently about the disparities in production between parent and child wells in US shale basins. The increased attention on the issue is part of broader concern among investors about the ability of operators to maintain high levels of output over the next few years. However, Doug Suttles, Encana president and chief executive officer, assures that shale executives are acutely aware of the parent-child challenge. His company has been โvery public about this for 5 years now,โ he said before an audience largely consisting of the investor community at CERAWeek by IHS Markit this week in Houston. He ultimately doesnโt think itโs โa big threatโ to the shale sector. ย ExxonMobil Makes Huge Gas Discovery Offshore Cyprus ExxonMobil has made what it says is the worldโs third-largest natural gas discovery in 2 years off the coast of Cyprus in the eastern Mediterranean Sea. Based on preliminary interpretation of the well data, the discovery could represent an in-place natural gas resource of up to 8 Tcf. The Glaucus-1 well, located in Eastern Mediterranean Block 10, encountered a gas-bearing reservoir of approximately 436 ft. The well was safely drilled to a depth of 13,780 ft in 6,769 ft of water. Industry consultants Wood Mackenzie told Reuters news agency that it estimated recoverable resources of Exxonโs field to be 4.55 Tcf. That compares with its 6.4ย Tcf estimate for Calypso, found by Italyโs ENI and Franceโs Total last year.
- North America > United States > Texas (1.00)
- Asia > Thailand (1.00)
- Government > Regional Government > Asia Government > Thailand Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (33 more...)
Technology Focus Carbon-dioxide (CO2) injection is a successful enhanced-oil-recovery (EOR) technology that has been deployed extensively in the Permian Basin of West Texas, enabled by CO2 mostly produced and transported from naturally occurring CO2 reservoirs in Colorado and New Mexico. Further expansion of CO2 EOR has been limited by the availability of affordable CO2 rather than the existence of suitable target reservoirs for redevelopment with CO2 EOR. The US Department of Energy estimates that 67 billion STB of economically recoverable next-generation CO2-EOR oil exist in US conventional reservoirs, with significant potential identified in other oil provinces around the world. This situation may be about to change. On 9 February, Congress passed and the president signed into law a budget agreement that included language to expand a 2009 tax credit for CO2 capture and storage known as 45Q. The key provisions are that, for stored CO2, the tax credit rises to $50 per tonne in 2027, while, for EOR, the equivalent value is $35. The amounts will be adjusted for inflation after 2026. The tax credit is per tonne of CO2 captured as long as it can be established that the CO2 was stored. The tax credit is transferable, hence nontax-paying entities or entities that have no tax liability can benefit from the program. The credit goes to the facility that captures the CO2 and is available for the first 12 years of operation. There is no cap on the arrangement for the tax-credit projects coming online after 2018 or for which construction has started before 2024. As a result, the US now has a carbon-pricing mechanism that could well be enough to unlock a wave of innovative CO2-capture projects and lead to a significant expansion in CO2 EOR, ultimately leading to new infrastructure, storage sites, and technology improvements that give birth to a CO2-capture industry. Recommended additional reading at OnePetro: www.onepetro.org. SPE 185526 Surveillance and Initial Results of an Existing Polymer Flood: A Case History From the Rayoso Formation by L.A. Martino, YPF, et al. SPE 188363 A Field Case Study of an Interwell Gas Tracer Test for Gas-EOR Monitoring by Modiu Sanni, Saudi Aramco, et al. SPE 185734 Case Histories of Solvent Use in Thermal Recovery by Bita Bayestehparvin, University of Calgary, et al.
- North America > United States > Texas (0.91)
- North America > United States > New Mexico (0.57)
- Asia > Middle East > Saudi Arabia (0.57)
- North America > Canada > Alberta > Census Division No. 6 > Calgary Metropolitan Region > Calgary (0.26)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Middle East Government > Saudi Arabia Government (0.57)
- Government > Regional Government > North America Government > United States Government (0.55)
- South America > Argentina > Mendoza > Rayoso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- (22 more...)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Management > Professionalism, Training, and Education > Communities of practice (1.00)
- (2 more...)
E&P Notes First Offshore Drilling Merger: Ensco Buys Atwood Oceanics Trent Jacobs, JPT Digital Editor Offshore drilling contractor Ensco is set to buy smaller rival Atwood Oceanics in an all-stock transaction valued at USDย 850ย million. The deal marks the first such corporate acquisition in the offshore drilling sector since the onset ofย the oil and gas industry downturn. The merged enterprise will be the worldโs largest owner of a mixed-offshore drilling fleet with 63 rigsโ26 deepwater floating rigs and 37 jackups. The breakdown of the additions coming from Atwood Oceanics include four deepwater drillships, two semisubmersibles, and five jackups. Pending regulatory approval, the deal is expected to close later this year. ย Wild Well Control Aims To Tame Leaky Wells Trent Jacobs, JPT Digital Editor As blowouts become a less frequent event in the US, specialty-outfit Wild Well Control is eyeing the market potential of the less severe, but more common, issue of sustained casing pressure in shut-inย wells. โWe used to say that the rule of thumb in the US was one blowout per 1,000 wells drilled,โ said Bill Mahler, executive vice president at Wild Well. โToday, itโs more like one blowout for 1,600 wells drilled.โ ย Permian Production Boom To Continue, Says Laredo CEO Joel Parshall, JPT Features Editor Production in the Permian Basin will continue to boom and grow by more than 25% by next year, said Randy Foutch, CEO of Laredo Petroleum, in a talk held by the Independent Petroleum Association of America (IPAA) and the Texas Independent Producers and Royalty Owners (TIPRO). Speaking at the IPAA/TIPRO Leaders in Industry luncheon, Foutch said that the 395 drilling rigs operating in the Permian region are as productive as the 641 rigs that were operating there before the collapse in oil prices in late 2014. ย These are the Forks in the Road to Drilling Automationย Trent Jacobs, JPT Digital Editor The low price of crude may have slowed the advance of drilling automation technology, but it clearly has not stopped it. Uptake is rising, chiefly in the US onshore market, where contractors including Nabors and Precision Drilling have recently rolled out their first batch of โclosed-loopโ automated rigs that take key pieces of the well construction process out of human hands. Service giant Schlumberger is doing the same after it acquired a number of drilling technology firms in recent years, including one that developed rig control systems for the competitionโa factor that has been seen as incentivizing other drilling contractors to accelerate their automated ambitions. ย Data and Digital Hold E&Pโs Future, Says New Century CEOย ย Joel Parshall, JPT Features Editor Phil Martin, CEO of New Century Exploration, urged US E&P companies to leverage data and rapidly adopt digital technology in a talk at the Leaders in Industry luncheon held by the Independent Petroleum Association of America and the Texas Independent Producers and Royalty Owners Association recently in Houston.ย Titling his presentation โHope is not a Strategy,โ Martin urged companies to move quickly to take advantage of data-driven opportunities.
The undulating trajectories common to horizontal wells are the source of one of their greatest pain pointsโgas slugs. When these fast-moving accumulations reach the internals of an artificial lift system, a best case result may be a momentary pause in production. On the other hand, a gas slug could represent the bitter end for a lift system that may have cost six figures. The problem has been serious enough to drive operators in the Permian Basin to adopt an artificial lift strategy not historically used there. Manufacturers have responded to the challenge by trying to make pumps more slug-tolerant, while others are marketing automatic shut-down systems for asset protection.ย HEAL Systems has taken a different tact with a technology that it says removes slugging from the production equation by separating the horizontal from the vertical well sections and regulating the flow between them. The emerging innovation is called a horizontal-enhanced artificial lift (HEAL) system. It has no moving parts, and can be connected to any variant of lift system.ย ย In May, the company gained commercial steam through a joint venture with Schlumberger. Partnering with the service company will give HEAL Systems (formerly known as Production Plus Energy Services) manufacturing support and elevate its visibility in key markets such as the Middle East. โWeโve recognized that as a small company, scaling up is a challenge,โ said Jeff Saponja, the chief executive officer of HEAL Systems, adding that the goal of the joint venture โis to get this technology out there, grow the company faster, and have access to an incredible research capability to develop it to the fullest.โ Production Plus shareholders retain the majority share of the joint venture, allowing it to continue to market HEAL units to other service outfits and pumpย manufacturers. Based on its more than 200 installations in the US and Canada, the company is touting data that show its product has extended the run life of pumps in shale wells by months and sometimes years. Highlighted case studies of multiple wells in different formations claim this longevity has generated production improvements of 40โ100% above prior baselines.
- North America > United States > Texas (0.25)
- North America > United States > New Mexico (0.25)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
The standard for progress in shale development has been the drastic reduction in the number of days needed to drill a well, from more than 20 to less than 5 in some unconventional plays. But some question whether it has become a misleading metric for an industry needing more productive wells. โThe human tendency is to optimize within a given constraint. Right now, it is reaching the total depth in the shortest time,โ said Robello Samuel, technology fellow, drilling, at Halliburton. โIf all you care about is that quantification, you do not worry about tool damage or wellbore quality, or what it is like to complete it.โ Maximizing drilling performance and efficiency is not the same as optimizing it, he said. โEveryone needs to remember why they are drilling the hole. As much oil and gas needs to come out as possible,โ said Bart Critser, geosteering manager for Terra Guidance. โOtherwise itโs just a multimillion dollar, fancy hole in the ground.โ The payoff for drilling faster has largely been realized. While further time savings are possible, the discounts now offered by service companies hungry for work have slashed the potential savings. In September, the day rate for a typical rig in the Permian Basin was USD 18,000, according to Hart Energy Market Intelligence. That is equivalent to only 360 bbl of oil at USD 50/bbl. Saving a day of drilling is a bad trade if the hole quality suffers. The downsides of a badly drilled well can range from casing damage and pump breakdowns, to missed sweet spots and accumulations of sand in low spots slowing the flow, according to drilling experts at the recent SPE Annual Technical Conference and Exhibition (ATCE) held in Houston, and in interviews since. One of them, Moray Laing, oil and gas lead for the SAS Americas Energy Practice, raised a seemingly simple question: โHaving good directional control gives you better wellbore quality. I wonder why we are not measuring that systematically?โ The Search for Measures of Drilling Imperfection
- North America > United States > Texas (0.34)
- North America > United States > New Mexico (0.25)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (23 more...)
Editor's column The issue of water needs for shale resource development has largely focused on public concern about possible constraints on water supplies, particularly in areas suffering from drought. A new study suggests that without technological breakthroughs or changes in how the oil and gas industry manage water, development of shale production could be hampered in areas with the largest estimated reserves. Some cities in the United States suffering from drought have imposed bans on hydraulic fracturing, even though oil and gas industry water use compares favorably with that of other industries (see Beyond the Headlines, July 2014 JPT, p. 20). The new report issued by the World Resources Institute, titled โGlobal Shale Development: Water Availability and Business Risk,โ focuses not on public concerns, but energy company risk instead. It contends that water-availability challenges could limit shale resource development on six continents, including in areas with some of the greatest potential for shale production. The reportโs executive summary looks at three countries in particular and assesses the potential water challenges. China. The worldโs largest energy producer and consumer also has the worldโs largest technically recoverable shale gas resources, according to estimates from the US Energy Information Administration (see table, p. 86). But most of these resources are located in areas of โhighest water stress,โ according to the study. More than 60% of the resources are in areas with arid conditions or highbaseline water stress. Although Chinese oil companies recently have increased expenditures for shale development, the Chinese government in August cut in half its 2020 shale gas target after several years of disappointing E&P efforts. Argentina. Approximately 28% of this countryโs shale gas resources, the worldโs second-largest according to the EIA, are located in arid areas. Argentina has also had production success, with the joint venture between Chevron and YPF more than tripling production in the Neuquen basin shale formation known as Vaca Muerta from last year. United Kingdom. Public concern about hydraulic fracturing runs high, but the government recently began offering tax incentives to jump-start shale development. Given the high industry and public demand for water, the report classifies a third of the UKโs shale resources in the high to extremely high water stress category. The instituteโs mission is concerned more with the environment than with energy development and production, but its warnings are not considerably different from other recent studies, such as one done by consultants Wood Mackenzie last year titled โTroubled Waters Ahead?โ It noted that although agriculture uses two-thirds of global freshwater supplies, energy is by far the largest industrial user (more than 15%). The United Nations is predicting a 40% decrease in freshwater supplies by 2030, which will put additional focus on the amount of water used by oil and gas concerns. The solution may lie in technology development and better water management. Already the industry has made strides in water reuse and recycling, such as in the Permian Basin, an area facing extreme drought conditions (see p. 68). Numerous research projects are under way throughout the industry that could result in sharp cuts in demand for fresh water or the elimination of fresh water use within a few years. JPT
- South America > Argentina > Neuquรฉn Province > Neuquรฉn (0.56)
- North America > United States > New Mexico (0.36)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- South America > Argentina > Mendoza > Neuquen Basin (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- (22 more...)
New and Improved Proppants Carbo Ceramics and Saint-Gobain Proppants are headed for a battle for crush test supremacy. At the recent 2013 SPE Annual Technical Conference and Exhibition (ATCE), the two large proppant makers rolled out a new class of ultraheavy proppant built to stand up to the extreme stresses found on the frontiers of deepwater exploration. By next year, both companies plan to be mass producing ceramic grains that they said will be the strongest in the market, able to withstand stresses of 20,000ย psi or more. The new materials and manufacturing methods used to raise the crush test limit from around 15,000 psi will influence how they produce higher performing proppant for use in lower stress environments. โOn the process side, this will allow us to change everything we do,โ said Gary Kolstad, chief executive officer and president of Carbo. Called Kryptosphere, Carboโs new product is strikingly uniform in size and shape, with each grain looking like a tiny pingpong ball. The material and the look are a break from sintered bauxite, which has long been used in the most extreme conditions. At its ATCE booth, Saint-Gobain Proppants played up its new high-performance product, named Titan, which it said could stand up to pressures as high as 30,000 psi. Both new proppants are made of new materials put together using different manufacturing methodsโneither company would offer details. Their customers are operators in places such as the Lower Tertiary trend in the US Gulf of Mexico, where fracturing is required in wells that can go more than 30,000 ft below the mudline in water approaching 10,000 ft. There were other indications of proppant innovation at the ATCE. Oxane Materials was presenting its first field test information for the proppant it developed using new materials to create particles it says are significantly stronger per pound and were the first to be so uniformly spherical. Santrol was showing off its recent acquisition, a buoyant coating for proppant that is supposed to help proppant travel deeper into formations. The subsidiary of Fairmount Minerals acquired the inventor of the self-suspending proppant technology earlier this year and has been working to modify the material activated by absorbing water, so it can be used in humid places. Field tests were set to begin in November to see if it could be an effective alternative to the gels used to thicken drilling fluids for delivering heavy proppant. The coating was tested by Stim-Lab, which found that it did not interfere with equipment, such as blenders. โFrankly, I was pleasantly surprised it has interesting properties,โ said Michael Conway, president of Core Labโs Stim-Lab division. โWe will find out soon if it makes a material difference in production.โ
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.94)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation (0.94)
- North America > United States > Montana > Williston Basin > Bakken Shale Formation (0.94)
Summary Transient tests can be used throughout the life of the reservoir to manage and to optimize recovery of hydrocarbon fluids. This paper shows applications of various well-testing methods during the exploration, appraisal, and primary and secondary recovery phases of field projects. Single-well tests [e.g., drillstem tests (DST's) and buildup tests] are primarily used during the various stages of field development and primary recovery, whereas multiple-well tests (e.g., interference tests) are most often used during secondary recovery. A clear understanding of the type of information obtained from well tests is essential if this information is to be used properly in managing the reservoir. Examples are the different values of permeabilities calculated from single-vertical-well, horizontal-well, and multiple-well tests; the values of average reservoir pressures; and the double-porosity parameters calculated from tests in naturally fractured reservoirs. The state of the art of testing and measurement tools, acquisition systems, and interpretation methods affects the type of information obtained from well tests and should be considered by the petroleum engineer before results are used. The paper presents information to help the engineer use transient tests properly and to their fullest extent. Field examples are used when appropriate. Introduction The main difference between petroleum engineering and most other engineering disciplines is that the systems that petroleum engineers work with are given to them, whereas in other engineering disciplines the engineers design their systems. For example, the car engine is designed by a mechanical engineer and the structure of a building is designed by a civil engineer. Oil and gas fields are not designed or developed by petroleum engineers. They are given to them. As a matter of fact, the biggest challenge petroleum engineers face is to characterize these systems. In this regard, petroleum engineers have the same problem as mining and meteorological engineers and groundwater hydrologists. However, petroleum engineers have the added complexity, which mining and meteorological engineers do not have, of being unable to see the in-situ properties of our systems physically and measure them directly. Therefore, to obtain the physical properties of hydrocarbon-bearing formations, petroleum engineers rely on indirect measurements, such as inferring formation permeability from production data, calculating porosity from a sonic log, or determining the distance to a fault from a buildup test.
- North America > United States > Texas (0.94)
- North America > United States > Alaska > North Slope Borough (0.28)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock (0.46)
- North America > United States > Texas > Permian Basin > Midland Basin > Amacker-Tippett Field > Strawn Formation (0.99)
- North America > United States > Texas > Permian Basin > Midland Basin > Amacker-Tippett Field > Ellenburger Formation (0.99)
- North America > United States > Alaska > North Slope Basin > Kuparuk River Field > Kuparuk Field (0.99)
- (2 more...)
Summary Significant economic benefits can be derived from the application of reservoir management. The key elements in economical reservoir management are the efficient use of available resources and optimization of reservoir exploitation through a multidisciplined approach. This paper describes various aspects of and approaches to reservoir management and provides case histories that support the findings. Introduction The genesis of this article was my participation in an SPE-sponsored reservoir management seminar in 1992. The invitation to speak on the economics of reservoir management arose from my experience in evaluating reservoir exploitation projects. However, after some reflection, I began to have doubts concerning what the economic considerations unique to reservoir management were. Reserve evaluations are not handled differently just because reservoir management is involved. Likewise, economic hurdle rates are unique to the particular company and have nothing to do with the study process. In a previous seminar, methods of financing projects were discussed. This was interesting but not normally the direct concern of those involved in reservoir management. What then are the unique economic aspects of reservoir management, if any? The answer seemed to lie within the reservoir management process itself. What is reservoir management? Haven't reservoir engineers been doing this for years? Why all the hype about something that's not a new technology, not even a new concept? Most literature on reservoir management is centered around exploitation of large reservoirs in frontier areas of the world. Does reservoir management have a meaningful role in small reservoirs or mature producing basins? The leading advocates of reservoir management are usually experts in numeric simulation. Is reservoir modeling the essence of reservoir management? Only as these issues about the nature and use of reservoir management were examined did a rationale for the economic aspects develop. What Is Reservoir Management? Perhaps this question has been best answered in the negative. Reservoir management is neither a new technology nor the latest management consultant buzzword to justify corporate reorganization. While philosophical aspects to reservoir management exist, it is not an attempt to introduce Japanese management philosophy into petroleum engineering (e.g., total quality management). Reservoir management has been described as (1) repackaging existing technology, (2) managing advanced technology, (3) long-range/strategic planning, (4) team approach to problem solving, and (5) common sense. All of these contain an element of truth.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (26 more...)