This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 200577, “Applications of Artificial Neural Networks for Seismic Facies Classification: A Case Study From the Mid-Cretaceous Reservoir in a Supergiant Oil Field,” by Ali Al-Ali, Karl Stephen, SPE, and Asghar Shams, Heriot-Watt University, prepared for the 2020 SPE Europec featured at the 82nd EAGE Conference and Exhibition, originally scheduled to be held in Amsterdam, 1-3 December. The paper has not been peer reviewed. Facies classification using data from sources such as wells and outcrops cannot capture all reservoir characterization in the interwell region. Therefore, as an alternative approach, seismic facies classification schemes are applied to reduce the uncertainties in the reservoir model. In this study, a machine-learning neural network was introduced to predict the lithology required for building a full-field Earth model for carbonate reservoirs in southern Iraq. The work and the methodology provide a significant improvement in facies classification and reveal the capability of a probabilistic neural network technique. Introduction The use of machine learning in seismic facies classification has increased gradually during the past decade in the interpretation of 3D and 4D seismic volumes and reservoir characterization work flows. The complete paper provides a literature review regarding this topic. Previously, seismic reservoir characterization has revealed the heterogeneity of the Mishrif reservoir and its distribution in terms of the pore system and the structural model. However, the main objective of this work is to classify and predict the heterogeneous facies of the carbonate Mishrif reservoir in a giant oil field using a multilayer feed-forward network (MLFN) and a probabilistic neural network (PNN) in nonlinear facies classification techniques. A related objective was to find any domain-specific causal relationships among input and output variables. These two methods have been applied to classify and predict the presence of different facies in Mishrif reservoir rock types. Case Study Reservoir and Data Set Description. The West Qurna field is a giant, multibillion-barrel oil field in the southern Mesopotamian Basin with multiple carbonate and clastic reservoirs. The overall structure of the field is a north/south trending anticline steep on the western flank and gentle on the eastern flank. Many producing reservoirs developed in this oil field; however, the Mid- Cretaceous Mishrif reservoir is the main producing reservoir. The reservoir consists of thick carbonate strata (roughly 250 m) deposited on a shallow water platform adjacent to more-distal, deeper-water nonreservoir carbonate facies developing into three stratigraphic sequence units in the second order. Mishrif facies are characterized by a porosity greater than 20% and large permeability contrast from grainstones to microporosity (10-1000 md). The first full-field 3D seismic data set was achieved over 500 km 2 during 2012 and 2013 in order to plan the development of all field reservoirs. A de-tailed description of the reservoir has been determined from well logs and core and seismic data. This study is mainly based on facies log (22 wells) and high-resolution 3D seismic volume to generate seismic attributes as the input data for the training of the neural network model. The model is used to evaluate lithofacies in wells without core data but with appropriate facies logs. Also, testing was carried out in parallel with the core data to verify the results of facies classification.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 199941, “Interpretation of Electromagnetic-Wave Penetration and Absorption for Different Reservoir Mineralogy - Quartz-Rich, Limestone-Rich, and Clay-Rich - and at High- and Low-Water Saturation Values for a Bitumen Reservoir,” by Matthew Morte, SPE, Hasan Alhafidh, SPE, and Berna Hascakir, SPE, Texas A&M University, prepared for the 2020 SPE Canada Heavy Oil Conference, originally scheduled to be held in Calgary, 18–19 March. The paper has not been peer reviewed. Interpretation of logging data generated through electromagnetic (EM) waves or determination of EM-wave propagation in a medium as an enhanced-oil-recovery (EOR) method are not easy tasks. The complete paper aims to identify the role of different geological settings with different types of fluid saturations in the response of EM-wave propagation and absorption. Several correlations were created in this study and can be used to better interpret the reservoir mineralogy and fluid saturation as a response to EM-wave logging. Moreover, these results can be used to estimate the effective area (penetration depth) of EM waves as an EOR method. Experimental Procedure Complex permittivity of synthesized rock samples was recorded by means of a vector network analyzer as the source and a dielectric probe kit as the transmitter. The dielectric probe behaves as both the transmitter and receiver simultaneously by measuring the proportion of the reflected wave. The dielectric probe is capable of measuring both the solid interface, as is the case with the synthesized reservoir rock, and fluids. The output of the vector network analyzer is both the dielectric constant, defined to be the real-portion complex permittivity, and the loss index, defined to be the imaginary portion. The loss tangent is a parameter that describes the overall efficacy of the material as a microwave absorber with higher values corresponding to higher heat generation in the reservoir. Reservoir properties of interest are isolated by taking advantage of experimentally defined synthesized cores. Variable properties are achieved by introducing a known quantity of specified materials to ensure control over the outcome of representative reservoir rock. Samples are an unconsolidated mixture of both the skeletal frame (rock matrix) as well as the pore space. The rock matrix is comprised of a systematic and stepwise variability of quartz sand, limestone sand, and kaolinite clay or bentonite clay. The fraction of each introduced mineral is manipulated to isolate the contribution of the individual components. The weights of the introduced constituents are calculated to result in a synthetic rock matrix with the desired rock mineralogy. The first batch of synthesized cores consisted of 75 mixtures. The remainder of the contrived cores were limestone. A separate 20 experiments were performed to account for the presence of both pore-filling and swelling clays, namely kaolinite and bentonite, respectively. Compaction and blending of the cores were performed by hand; homogenization of the mixture was ensured by thorough mixing.

2020 set the stage for a profound transformation in the oil and gas industry. The oil and gas industry was already facing a challenging transition process as economies move toward a low-carbon future; however, surviving and prospering in a low-oil-price and high-risk environment is an even greater and more urgent challenge. Producers with relatively high-cost production will bear the brunt of production curtailments, since none are able to sustain uneconomic production for very long. In the years leading to 2019, shale plays stole the show, increasing production as long as prices sustained the frantic pace of drilling required for the production increases observed in the US. On the other hand, the intrinsic characteristics of deepwater plays - highly front-loaded investments and long project cycles - worked against them. Relatively low prices that were just as challenging for shale plays were considered a reason to delay deepwater projects (Rigzone 2016). Portfolio diversification is an important risk-mitigation strategy, whether by region, country, environment, or play type. However, for the majors of the industry, it is increasingly difficult and risky to rely on many relatively small projects to keep their portfolio pipeline full. Given the size of large companies, large projects are required to guarantee high levels of production over long periods and to keep their project portfolio manageable. Larger plays, and those that are less subject to environmental restrictions, tend to be found in large offshore basins, where deepwater plays dominate. At the same time, the world offers fewer opportunities with acceptable country risk. Thus, larger plays in safer regions have become essential elements of the core business of large oil and gas players. Besides offering the potential for large production, deepwater plays often can provide low Opex because of their scale and productivities, such as in the Brazilian pre-salt trend (the “pre-salt”), where many wells have consistently delivered sustained average production above 40 thousand BOPD (ANP 2020). Furthermore, deepwater plays involve large, complex projects that are well suited to the megaproject management capabilities of large players of the industry. Those projects are also amenable to technological innovations that have delivered impressive performance improvements and cost reductions. As an example, Petrobras claims that in 2020 its lifting costs for deepwater pre-salt fields have come down to below $3.00/bbl, and under $5.00/bbl including rig-leasing costs (Petrobras 2020a). As to innovation-related gains, two Petrobras programs represent unprecedented achievements in deep waters. Prod1000 expects to reach first oil within 1,000 days of a discovery, and Exp100 seeks to achieve a 100% discovery rate in exploratory wells, a feat that breaks the paradigm that has assigned high exploratory risks to deepwater exploration everywhere in the world (Petrobras 2020b). Existing infrastructure in deepwater plays has also become key in locating exploration and production (E&P) activities, since it can lower Capex and aid the viability of projects that would otherwise be uneconomical.

“Down but not out” is how Westwood Global Energy Group described exploration drilling in an article based on its State of Exploration 2020 Report. The Baker Hughes rig count provides supporting details. On 12 May, the data showed 339 active rigs in the United States - the lowest level since the rig count was introduced in 1987. On 1 June, the US count plunged to 301 in its 12th week of losses. At the worst of the 2014-2016 oil bust - the previous lowest point on record - 404 rigs were operating. The worldwide rig count for May was 1,176, down 338 from the 1,514 counted in April and down 1,006 from the 2,182 counted in May 2019. And, Rystad predicted on 28 May that more than half of the world’s planned licensing rounds for 2020 are likely to be canceled. The consensus among industry experts is that exploration will be hit by some of the deepest cuts inflicted by the coronavirus pandemic, the biggest oil market crash in history, and the transition to a low-carbon energy future. The silver lining is that there is still a business case for exploration despite these difficult times. Julie Wilson, director of global exploration research for Wood Mackenzie, said in a recent virtual panel discussion that the role of exploration in replacing supply sources in current portfolios with “new and better” barrels of oil equivalent (BOE) will continue over the next 20 years. But for explorers to prosper, those barrels will need to be low in cost and emissions. Rude Awakening For the exploration sector, 2020 began with a degree of cautious optimism and increasing activity. Confidence had returned with improved performance, the highest commercial success rate (CSR) in 10 years, and the discovery in 2019 of several multi-billion-barrel plays. Explorers were keenly aware of challenges ahead, including investability, capital efficiency, the risks of exploring in deep water, and societal pressure to move toward energy transition. But, the overall outlook was for another 30 years of profitable exploration. At the start of the year, the high-impact well count had been expected to be similar or slightly higher than the 93 wells completed in 2019. Westwood now expects around 60 to 70 high-impact exploration wells to be completed by the end of 2020, a decline of up to 35% and back to the numbers and volumes seen from 2016 to 2018 following the 2014 oil price crash. In the Gulf of Mexico (GOM), the number of executed high-impact wells has declined from 34 to 15, all in deep water. Seven of those have been spudded. For independent GOM explorers, the number of expected wells went from 13 to one, as companies decided to focus their bare-minimum budgets on near-term production.

As ExxonMobil announced discovery after discovery offshore Guyana, it sounded easy. Beginning with the Liza-1 discovery well, the giant oil company announced 16 successful exploration wells. There were four or five successful wells per year from 2017 through 2019, ending with news of its 16th find in January—pushing its estimated oil in the ground to 8 billion bbl. For those who found the oil, the evidence they used to pick those drilling targets was hardly clear cut, and it took more than 90 years to get to that point. “In retrospect it wasn’t obvious, and that was why it took so long,” said Maria Guedez, exploration manager for Guyana and Suriname for ExxonMobil. While a timeline of the Guyana project includes “initiated oil and gas exploration activities in Guyana in 2008,” the story ExxonMobil presented at the recent AAPG SuperBasins 2020 conference covered exploration starts and stops going back to 1928 by the company’s predecessor, Standard Oil Co. One slide showed a typewritten report from the 1930s noting the test wells were “salted,” giving the impression of a rich reservoir, even though “there is no evidence of oil.” But ExxonMobil and other oil companies kept coming back. There were dry holes in the 1970s off nearby Suriname—the eastern extension of the play. They saw some positive signs, but the source rock was judged to be not mature enough to fill the conventional oil deposits needed to justify development. Finally, in the 1990s ExxonMobil geoscientists looking for new exploration opportunities used what had been learned, plus advanced seismic imaging, a better understanding of the movements of tectonic plates, and some simple analysis to outline a plan that ultimately led to the discovery. Guedez showed a picture of a simple chart evaluating the pros and cons of the basin with handwritten notes, and a geologic cross section in which a geologist hand-counted layers in shallow and deep waters to identify the elements of a productive play. “New data and technologies often trigger key insights, but you need to ask the right questions,” Guedez said. “Sometimes you don’t need massive amounts of data to make a difference.” Executing the concept required developing the ability to drill wells in water 8,000 ft deep and high resolution to seismic that allowed interpreters to see the subtle signs of hydrocarbon-rich stratigraphic traps. “The places where you have structure, it was hard [to spot anomalies]. Stratigraphic traps are normally just really difficult to explore. It was going to be difficult to hit without having some sort of high-resolution 3D seismic,” Guedez said. These anomalies are never easy to spot, but she said that compared to her experience in offshore Africa, signs of traps off Guyana were “remarkably subtle.” So far, they have hit on 89% of the wells drilled. “Once the eyes of the team got fine-tuned to that, they did a good job spotting them,” Guedez said.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 196208, “Value Creation From the Reservoir, Well, and Facilities Management (RWFM) Planning in Multistacked Mature Oil-Rim Reservoir, Offshore Sarawak, Malaysia,” by Yeek Huey Ho, SPE, Nor Baizurah Ahmad Tajuddin, SPE, Muhammed Mansor Elharith, SPE, Hui Xuan Dan, Kwang Chian Chiew, Kok Liang Tan, SPE, Raj Deo Tewari, SPE, and Rahim Masoudi, SPE, Petronas, prepared for the 2019 SPE Annual Technical Conference and Exhibition, Calgary, 29 September–2 October. The paper has not been peer previewed. The XamXung field offshore Sarawak, Malaysia, is a 47-year brownfield with thin remaining oil rims that have made field management challenging. The dynamic oil-rim movement has been a key subsurface uncertainty, particularly with the commencing of a redevelopment project. A reservoir, well, and facilities-management (RWFM) plan was implemented to optimize development decisions. This paper is a continuation of paper SPE 174638 and outlines the outcome of the RWFM plan and the results’ effect on development decisions such as infill well placement and gas/water injection-scheme optimization (Fig. 1). Key decisions affected by the RWFM findings are highlighted in the complete paper. Introduction The XamXung field was discovered in 1967, with commercial production established in 1972. The field is a simple faulted anticline bounded by two major faults in the north and south. The field consists primarily of clastic deposits characterized by thick sands interbedded with thin shale layers of late Miocene to Pliocene age. The field consists of multiple stacked gas and oil reservoirs, with key producing intervals being the oil-rim reservoirs XE/XF and XH/XI, and the deeper oil reservoir XL, as well as major nonassociated gas reservoirs XA, XC, XD, XM, and XN. The main discussion of the complete paper focuses on XE/XF and XH/XI reservoir redevelopment. XE/XF is a saturated oil-rim reservoir with initial oil-rim thicknesses of 95 and 85 ft, respectively. The XE/XF oil rim is overlain by a gas cap with m size (ratio of initial free-gas reservoir volume to initial reservoir oil volume) of 1.1 and 0.4, respectively. XE and XF reservoirs are separated by a fieldwide sealed shale layer of 10–20-ft thickness. Initial reservoir pressure and well log data acquired during the early production his-tory suggested that XE/XF reservoirs originally shared a common gas/oil con-tact (GOC) but different free-water levels. XE/XF reservoirs have an average porosity of 27–32% and average permeability of 500–1500 md. They started production in 1974 and reached peak production in 1977. The reservoir pressure has declined by only 200 psi after 45 years of production, indicating that the reservoir is under a strong aquifer drive. Gas injection into XE reservoir commenced in 1995 following an increasing water-cut trend in most of the producers, with the objective to counteract the aquifer influx and to allow uniform gas-cap gas expansion throughout the reservoir. However, the reservoir historically has produced more free gas compared with the amount of gas reinjected, resulting in the reservoir gas-cap shrinkage.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 191455-18IHFT-MS, “Twelve Years and 12,000 Multistage Horizontal Wells in the Bakken: How Is Industry Continuing To Increase the Cumulative Production per Well?” by C. Mark Pearson, SPE, Larry G. Griffin, SPE, Stacy L. Strickland, SPE, and Paul M. Weddle, SPE, Liberty Resources, prepared for the 2018 SPE International Hydraulic Fracturing Technology Conference and Exhibition, Muscat, Oman, 16–18•October. The paper has not been peer reviewed. Multistage horizontal well designs were first implemented in the Bakken in 2007. Since then, more than 12,000 wells have been completed in either the Middle Bakken or Three Forks zones. Early-time production rates, as measured by 180-day state-reported cumulative production, have increased fourfold during this period, during which industry has pursued a program of innovation and continuous improvement in completions technology, with production per well increasing in 10 of 12 years. Through a big data analytical study comparing geological data, completions parameters, and state-reported production results, the authors have evaluated the fundamental changes that have guided industry to these production rates during the period discussed. Geology The Bakken Formation is Mississippian and Devonian in age and consists of Upper, Middle, and Lower members. The focus of this paper is to review work in both the Middle Bakken member and the lower Three Forks intervals contained within the Bakken Petroleum System. The Upper and Lower Bakken shales are the prolific source rocks for the petroleum system. The Middle member consists of distinct lithofacies that range from silty sandstone on the east flank of the basin to silty dolomite on the west flank. Porosities in the Middle member range from 4–10% and permeabilities are generally less than 0.1 md. Fig. 1 shows the basin depth structure map with a color fill of the thermal maturity of the Upper Bakken shale. The onset of oil generation occurred at a pyrolysis temperature ( T max ) of greater than 430°F as indicated in the figure by shades of green and warmer colors. Oil generation in this thermally mature window created overpressure and resulted in oil mobilization into less- mature and immature regions toward the extremities of the basin. The Bakken is a basin-centered system and thus the increased pore pressure that occurred with the process of kerogen conversion and the generation of oil has resulted in pore pressure gradients as high as 0.9•psi/ft in the deepest part of the basin. Unsurprisingly, in the deepest part of the basin, water cut is the lowest, with increasing water cut with distance from the areas of greatest thermal•maturity.• The complete paper provides a detailed description of the Bakken development history, which the authors divide into seven periods beginning with first production in 1953 to the present. Production Bakken production has grown historically, but as recently as early 2004 it yielded only approximately 25,000 BOPD. The increase in drilling activity then drove production growth, with an initial peak in December 2014 of 1.22 million BOPD. The rapid decline in industry activity then resulted in a significant production drop. However, the decline reversed, and new production records of 1.23 and 1.24 million BOPD were set in June and July of 2018. The return to peak production levels has been driven by companies using more-effective•completions.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 192759, “Data-Driven Analytics: A Novel Approach to Performance Diagnosis Using Spatiotemporal Analysis in a Giant Field Offshore Abu Dhabi,” by Mohamed Mehdi El Faidouzi, SPE, and Djamel Eddine Ouzzane, ADNOC, prepared for the 2018 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 12–15 November. The paper has not been peer reviewed. This work describes a heuristic approach combining mathematical modeling and associated data-driven work flows for estimating reservoir-pressure surfaces through space and time using measured data. This procedure has been implemented successfully in a giant offshore field with a complex history of active pressure management with water and gas. This practical work flow generates present-day pressure maps that can be used directly in reservoir management by locating poorly supported areas and planning for mitigation activities. Field Overview The giant oil field offshore Abu Dhabi covers an area of approximately 40×25•km. The structure is a low-relief anticline. The fault pattern is dominated by steep northwest/southeast strikes, with less-abundant northeast/southwest strikes. The fault throws are generally small, and most faults are unlikely to be sealing laterally. The oil accumulation is separated by dense argillaceous limestones into three distinct, stacked reservoirs (A, B, and C), each approximately 20 to 35 ft thick. Formation-pressure tests showed good intrareservoir vertical pressure communication. Occasionally, especially toward the north and east, a generally tight clay-prone lithology forms a localized barrier between the upper and basal layers of Reservoirs A and B. The complete paper examines the case of the upper layers of Reservoir A in particular, a laterally extensive porous carbonate deposited in a shallow-water environment, although the work flows developed are equally applicable to other reservoir zones. Commercial production of Reservoir A began in the late 1960s. After an initial period of natural depletion, various pressure-maintenance strategies were deployed, namely dump-flood (1972–1984), peripheral water injection (from 1979), and crestal gas injection (from 2005). Spatiotemporal Analysis of Pressure Data Prediction of spatial random fields is a common task in geostatistics and arises in geology, mining, hydrology, and atmospheric sciences. Kriging procedures are used routinely to make optimal predictions at unsampled locations. For quantities that vary in space and time, such as reservoir pressure, spatiotemporal interpolation can provide more-accurate predictions than purely spatial interpolation because observations at other times are considered. In producing oil and gas assets, reservoir-pressure measurements are made at a much higher frequency in the time domain compared with the spatial domain, which requires additional wells to be drilled. The conventional approach of using a spatial interpolation on the basis of a certain time period misses valuable information and could result in inconsistencies between maps from one time period to the next. In this case study, the authors present a heuristic approach to estimating reservoir pressure maps in Reservoir A on the basis of spatiotemporal interpolation. Reservoir pressure is modeled using smooth functions that capture global trends while preserving the spatial and temporal continuity of pressure and pressure gradient. The residuals can be described by a stationary and spatially isotropic process. Residuals then can be predicted at unsampled space and time locations by kriging.

At some point during the first half of this year, Colombia replaced politically and economically crippled Venezuela as Latin America’s third-largest oil-producing country. That put Colombia behind only Brazil and Mexico in the hydrocarbons-rich region, two nations on divergent paths in terms of oil flow. Since Brazil ended state-owned Petrobras’ monopoly and opened up its industry to international companies in the late 1990s, the country’s oil output has almost tripled as it found and tapped into its giant offshore presalt fields. Output from Mexico’s state-owned Pemex, meanwhile, has fallen to its lowest level since at least 1990, and President Andrés Manuel López Obrador is working to stymie energy reforms implemented in 2013 to rejuvenate industry in the country. With the lessons of its resource-rich neighbors in mind, Colombia finds itself in a similar position where it must carefully choose a path forward for its industry or risk squandering great potential, or worse, losing what took years to build. The Andean country in the early 2000s overhauled its regulatory framework, reduced government take, and held licensing rounds with the intent of attracting foreign investment. Oil production subsequently rose to more than 1 million B/D before dropping amid the global industry downturn. Output in May averaged just short of 900,000 B/D. The Colombian government is trying to build on the foundation established by those reforms by implementing a novel permanent, continuously open bidding process and exploring unconventional development. The aim is to replenish depleted oil and gas reserves and increase production. Based on its 2018 output, the country’s crude reserves are good for just 6.2 years, while its natural gas reserves would last 9.8 years, falling below the 10-year mark for the first time in decades, according to statistics from Colombia’s National Hydrocarbons Agency (ANH). But Colombia has long been seen by the global industry as a petroleum province with upside that surpasses just incremental reserves and production gains. All of its liquids and nearly all of its gas production is extracted conventionally onshore, meaning its offshore and unconventional sectors are nascent. Colombia, which shares a more than 2000-km border with Venezuela, has proven petroleum systems that have produced oil and gas for a century, and the application of horizontal drilling and hydraulic fracturing offers huge promise.• Maria Fernanda SuÁrez, Colombia’s minister of mines and energy, has said that unconventional development could triple the country’s oil and gas reserves. Standing in the way, however, has been public resistance to hydraulic fracturing, and pilot projects that would demonstrate its benefits are yet to get environmental approval. There is “game-changing potential—if the industry can get going with development,” said Ruaraidh Montgomery, research director at oil and gas research firm•Welligence Energy Analytics.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 190277, “Mechanistic Study for the Applicability of CO2-EOR in Unconventional Liquids-Rich Reservoirs,” by Dheiaa Alfarge, SPE, Iraqi Ministry of Oil and Missouri University of Science and Technology, and Mingzhen Wei and Baojun Bai, Missouri University of Science and Technology, prepared for the 2018 SPE Improved Oil Recovery Conference, Tulsa, 14–18 April. The paper has not been peer reviewed. Improved oil recovery (IOR) methods for shale-oil reservoirs are considered relatively new concepts compared with IOR for conventional oil reservoirs. Different IOR methods—including CO 2 , surfactant, natural gas, and water injection—have been investigated for unconventional reservoirs using laboratory experiments, numerical simulation studies, and limited pilot tests. For a variety of reasons, CO 2 injection is the most-investigated option. In this paper, numerical simulation methods of compositional models were incorporated with logarithmically spaced, locally refined, and dual-permeability reservoir models and local grid refinement (LGR) of hydraulic-fracture conditions to investigate the feasibility of CO 2 injection in shale oil reservoirs. Introduction Advancements in horizontal drilling and hydraulic fracturing enabled unconventional liquids-rich reservoirs (ULRs), such as shale and source-rock formations and very tight reservoirs, to change the oil industry. ULRs are characterized by pore throats of micro- to nanomillimeters and an ultralow permeability. Although different studies re-ported that these ULRs contain billions of recoverable oil barrels in place, it is estimated that less than 7% of the original oil in place can be recovered during the primary depletion stage. Production sustainability is the main problem behind the low oil recovery in these unconventional reservoirs. Oil wells in ULRs typically start with a high production rate, but show a steep decline rate in the first 3–5 years of production life because of the rapid depletion in the natural fractures combined with a slow recharge from the rock matrix. The logical steps of academic research such as experimental investigation, simulation studies, and pilot tests for examining the applicability of different unconventional IOR methods have just begun in the past decade. Applying one of the feasible IOR methods in most oil and gas reservoirs should be mandatory to increase the oil-recovery factor. However, the mechanisms of IOR methods in unconventional reservoirs are not necessarily the same as those in conventional reservoirs. The primary characteristics of unconventional reservoirs that might impair performing IOR operations are low porosity and ultralow permeability. As a result, finding IOR methods that are insensitive to these very small pore throats is a priority.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 28517, “Deepwater Extended-Reach-Well Planning Through Depleted Reservoirs,” by Beng-Hooi Shi, Jennifer Koh, Dexter Liew, and Guat-Lee Chio, Shell, prepared for the 2018 Offshore Technology Conference Asia, Kuala Lumpur, 20–23 March. The paper has not been peer reviewed. Copyright 2018 Offshore Technology Conference. Reproduced by permission. This paper describes challenges faced in a company’s first deepwater asset in Malaysia and the methods used to overcome these issues in the planning stage. Because of the depleted nature of all three reservoirs located above the untapped reservoir, a need exists to drill through these depleted intervals with an extremely narrow margin window (less than 0.5 lbm/gal). An added complexity is the location of the reservoir, directly below a hydrates bulge. To address the challenges of this well, an integrated approach between various disciplines has proved to be a critical success factor. Introduction The field is offshore Sabah. The first phase of the development was completed in 2014, with 16 wells drilled. The development includes gas reinjection and seawater injection. The hydrocarbons are trapped in a four-way dip closure developed in an anticline structure containing four sand reservoirs separated by sealing shale layers. The Phase 1 development targeted the two main reservoir units (B and C) in the middle of the four reservoir sands. The pressure maintenance for the development of these two main reservoir units is provided by a combination of downdip water injection in the water leg and crestal gas injection in the gas cap. The second phase, comprising two oil producers and two water injectors, aims to maintain the oil-production plateau. One of the Phase 2 objectives is to target the deepest untapped reservoir (D) in the field with Well 4. However, as mentioned previously, Well 4 must drill through depleted intervals with extremely narrow drilling margins. Two of the four wells (Wells 1 and 2) only will drill into the depleted B reservoir in the final reservoir hole section, while the third well will cross the depleted B reservoir before drilling into the depleted target reservoir, C, in the final hole section. Phase 2 will offer the opportunity to acquire further data. Because of the stacked arrangement of Reservoirs A, B, C, and D and the wells targeting different reservoirs, a possibility exists to sequence the drilling campaign in a batch mode and to use data acquisition, operational learnings, and prediction validation before committing to drilling the intermediate and reservoir sections of the most difficult well (Well 4). The projected formation pore pressure and fracture gradient (PPFG) poses significant drilling challenges because of depletion plus the geomechanical requirements. The Reservoir C water injector is predicted to have a limited drilling margin because of the depletion of Reservoir B.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 189569, “Fines Migration During CO2-Saturated Brine Flow in Carbonate Reservoirs With Some Migratory Clay Minerals—Malaysian Formations,” by Y. Sazali, Petronas; S. Godeke, SPE, Universiti Brunei Darussalam; W.L. Sazali and J.M. Ibrahim, Petronas; G.M. Graham and S.L. Kidd, Scaled Solutions; and H.A. Ohen, SPE, HPO Global Resources Ventures, prepared for the 2018 SPE International Conference and Exhibition on Formation Damage Control, Lafayette, Louisiana, USA, 7–9 February. The paper has not been peer reviewed. A high-carbon-dioxide (CO 2 ) carbonate gas field offshore Sarawak, Malaysia, is scheduled for development. Reservoirs in this region have an average clay content of 8%; more than 50% of this clay content is migratory illite, and 15% is migratory kaolinite. Therefore, fines migration exacerbated by this low-permeability rock becomes a potential production and injection problem. A study was conducted involving rock mineralogy and dynamic flow to evaluate factors contributing to potential fines-migration damage within the production and injection interval. Introduction Migration of fines is associated with oil and gas production in sandstones as well as carbonate reservoirs. Fine particles located on the surface of rock grains are affected by adhesion, drag, and electrostatic and gravitational forces. Drag and lifting forces detach the particle, whereas adhesion, electrostatic, and gravitational forces press the particle to the surface. Generally, the main sources of movable fine particles in sandstone reservoirs are kaolinite and illite clays. Kaolinite particles are flat plates usually stacked in the form of booklets. The surface area of clay minerals, for example, typically is large because of their structure and small size and is more reactive and prone to mobilization and migration. Once mobilized, the fine particles are retained by size exclusion if their size exceeds the pore-throat size of the matrix. Fines damage also occurs when several small fine particles reach a larger pore throat at the same time and compete for passage through the throat with the result of bridging and sedimentation. Usually, in the case of gas/water flow, the fines move with the wetting water phase. However, fines movement taking place before water movement has been observed in a number of gas reservoirs. The in-situ mobilization and migration of fines without a mobile wetting phase is primarily caused by hydrodynamic drag that exceeds the critical rate to mobilize the fines. It has long been realized during corefloods that colloidal controlled release of particles leading to fines migration may be caused by salinity change following flow rate that causes the fines to bridge at the pore throat. Generally, a decrease in salinity or an increased rate of salinity change leads to particle mobilization. This decrease in permeability caused by decreasing salt concentration has been found to be nonmonotonic.

E&P Notes CNOOC, Several International Firms Sign Agreements for Areas Offshore China China National Offshore Oil Corporation (CNOOC) has signed strategic cooperation agreements with nine international firms for two offshore areas in the Pearl River Mouth Basin off China. State-owned CNOOC said the agreements—which include Chevron, ConocoPhillips, Equinor, Husky, KUFPEC, Roc Oil, Shell, SK Innovation, and Total—are a first step in establishing what could be long-term cooperation on exploration and development of offshore Areas A and B. Each international firm has existing upstream operations in China. The 15,300-sq-km Area A lies in 80–120 m of water. Firms are open to explore its deep layers below the Paleogene Enping formation. The 48,700-sq-km Area B lies in 500–3,000 m of water. Firms can explore each layer beneath the surface of that area. How Does Vaca Muerta Stack Up vs. US Shale? Data Tell the Tale Matt Zborowski, Technology Writer For what seems like forever, the upstream universe has awaited the emergence of Argentina’s Vaca Muerta Shale as the international answer to US shale. In many regards, it already holds its own. In others, there is still much work to be done. Either way, 2018 and 2019 will mark a promising step forward for the play, according to data from research and consulting firm Rystad Energy. US shale plays grew exponentially during their development phases, with the number of horizontal wells completed shooting up year-to-year in their first 5 years of relevancy. Vaca Muerta shows potential for a similar activity surge given geology “as good or better than the majority of the US plays,” noted Ryan Carbrey, Rystad senior vice president, shale research, during a recent Vaca Muerta-focused webinar. Global Oil and Gas Exploration, Project Sanctions Expected to Rise in 2019 Matt Zborowski, Technology Writer Global discovered oil and gas resources and big project sanctions are expected to remain on the upswing through next year, according to separate industry outlooks from Rystad Energy and Wood Mackenzie. Internalizing lessons from a difficult last few years, operators are choosing investments more wisely and are now better prepared to deal with volatile oil markets, the consultancies concluded. “Oil and gas companies can cope with whatever is thrown at them in 2019,” said Tom Ellacott, Wood Mackenzie senior vice president. “Portfolios are set to weather low prices, and the recent slide in prices justifies the sector’s conservative mindset.” Straight Out of OPEC, Qatar Flexes Global Ambitions Trent Jacobs, JPT Digital Editor Fresh on the heels of its announcement to leave OPEC, Qatar is positioning itself to become an increasingly active player in global energy projects through minority partnerships with big explorers. Its most recent acquisition involves a 35% stake in Italian operating company Eni’s interest offshore Mexico. Late last year Qatar said that it would withdraw its 57-year membership in the Organization of Petroleum Exporting Countries and focus on increasing its natural gas production. Qatar is currently the world’s third-largest supplier of liquefied natural gas (LNG) behind Australia and the US. ExxonMobil Makes 10th Discovery Off Guyana, Lifts Resource Estimate by Another Billion Barrels Matt Zborowski, Technology Writer ExxonMobil’s Pluma-1 well off Guyana encountered 37 m of high-quality hydrocarbon-bearing sandstone reservoir, marking the firm’s 10th discovery in South America’s newest oil powerhouse. Located 27 km south of the Turbot-1 discovery on the southeast portion of the 26,800-sq-km Stabroek Block, Pluma-1 was drilled to 5,013 m in 1,018 m of water by the Noble Tom Madden drillship, which spudded the well 1 November. The major now estimates that its discovered recoverable resources for the block total 5 billion BOE, up 1 billion BOE from its previous estimate made over the summer, around the time that it announced its eighth discovery, Longtail, also on the southeast part of the block. Its ninth discovery came via the Hammerhead-1 well to the west. Mexico’s Giant Zama Discovery Gets New Interest Owner Matt Zborowski, Technology Writer Germany’s DEA Deutsche Erdoel AG has agreed to acquire privately held Sierra Oil & Gas, interest owner in six blocks in Mexico, including the giant Zama discovery. Sierra holds a 40% nonoperated interest in the 465-sq-km Block 7 containing much of the shallow-water Zama discovery, where appraisal drilling is under way. Zama is estimated to hold 400–800 million BOE of recoverable resources with estimated peak output of 150,000 BOE/D. Production is expected to start up by 2022–2023. Talos Energy is operator and Premier Oil is the other partner. Total Begins Production From Nigeria’s Giant Egina Field Total advanced its global deepwater campaign 29 December with the launch of production from the Egina Field 150 km offshore Nigeria. The Egina floating production, storage, and offloading vessel, which Total says is its largest ever, will be connected to 44 subsea wells and produce up to 200,000 B/D of oil. The field lies in 1600 m of water on Oil Mining Lease (OML) 130. Total says the project was developed 10% under budget, resulting in savings of more than $1 billion, driven in large part by a 30% reduction in average drilling time per well. The French major’s operating costs in Nigeria have been slashed by 40% during the last 4 years, Arnaud Breuillac, Total president, exploration and production, said in a news release. Oil Prices Take a 2014-Size Hit Stephen Rassenfoss, JPT Emerging Technology Senior Editor Oil prices fell sharply in late 2018, similar to 4 years ago, but this time around oil companies seem better able to make money at these price levels. The US Energy Information Administration (EIA) made those observations in a new report released in December, after a day of trading in which the benchmark US price closed at $47.20/bbl. Brent closed at $56.49/bbl. Companies that survived the price downturn that began in 2014 are in better shape now. “Most measures of profitability and balance sheet fitness indicate companies should be able to weather the recent price downturn,” the EIA report said.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 187143, “Maximization of Major Oil and Gas Project Value at Identification/Access Stage by Reframing of Exploration Strategy,” by V. Orlov, R. Oshmarin, A. Bochkov, SPE, and Y. Masalkin, Gazprom Neft, and S. Yakovlev, V. Ulyanov, and M. Danilin, NIS, prepared for the 2017 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 9–11 October. The paper has not been peer reviewed. The conventional approach to project-exploration strategic planning at the identification or access stage is focused usually on the confirmation of the presence of hydrocarbons and the reduction of uncertainty. At the end of the appraisal stage, the main purpose is to create a successful business case. However, a focus on the economic value of the entire project at the identification stage may lead to optimal exploration programs and increasing project expected monetary value (EMV). The objective of this case study is to describe a specific approach to establishing an exploration strategy at the initial stage on the basis of not only uncertainty reduction, but also early business-case development and maximization of future economic value. Project Framing on the Basis of Geological Options and Uncertainties The Pannonian basin, part of the Alpine orogenic system, is the largest Neogene basin in the intra-Carpathian area, surrounded by the Alpine, Carpathian, and Dinaric thrust belts and characterized by anomalous high-heat-flow values. Continental collision and shortening recorded in these thrust belts and the Pannonian basin extension with associated magmatic events were reported to be the main drivers of basin development. The Pannonian basin is an aggregation of extensional and transtensional Neogene depressions separated by coeval uplifts. The basin is fed by three main sedimentary sources: the Eastern Carpathians in the north and the Apuseni Mountains and Southern Carpathians in the east. The main sediment transport direction is northeast/southwest, but small-scale deltas prograde westward locally, sourced by the Apuseni Mountains and the South Carpathians. These differently oriented deltas merged in the Tomnatec depression. The latest significant onshore basin in the study area was discovered and developed in the late 1950s to the early 1960s. Approximately 68 oil structures and 66 gas structures were documented, and most production is concentrated in or around the deepest depressions, which most likely contain mature source rocks. More than one-quarter of the oil discovered in the entire basin is found in three fields. To analyze all available geological information and to increase exploration success, a Pannonian basin model was created, involving more than 40 team members from several countries and different scientific institutes over a 2-year period. The results of the basin modeling showed that, in terms of the licence blocks, some zones have a high probability for the detection of hydrocarbon reservoirs. The study area is within a depression; the main source rock is clay marl of the Endrod formation.

E&P Notes ExxonMobil’s Eighth Discovery Off Guyana Adds Another Development Possibility Matt Zborowski, Technology Writer ExxonMobil said it has “encountered 78 m of high-quality, oil-bearing sandstone reservoir” near the Turbot discovery southeast of the Liza field offshore Guyana. The supermajor’s eighth discovery in the burgeoning oil province could bring about a new development opportunity in the southeast portion of the 26,800-sq-km Stabroek Block. The first phase of development drilling on Liza field began in May. The Longtail-1 discovery well was drilled to 5,504 m in 1,940 m of water by the Stena Carron drillship, which spudded the well on 25 May. It is the second discovery in that area after the Turbot discovery of late 2017. The two discoveries’ estimated recoverable resources total more than 500 million BOE, said ExxonMobil. GE To Spin Off Baker Hughes Pam Boschee, Senior Editor GE is spinning off Baker Hughes (BHGE) in its strategic plan for growth and shareholder value creation. It plans to focus on aviation, power, and renewable energy. GE CEO John Flannery said these areas share technologies, digital and additive strategies, and business models. The separation from Baker Hughes will take place over the next 2 to 3 years as part of GE’s effort to “make its corporate structure leaner and substantially reduce debt,” the company said in a statement. GE Oil and Gas merged with Baker Hughes in July 2017, with GE holding a 62.5% stake. BHGE’s revenue on an annualized basis is $22 billion. GE Healthcare will also be separated into a standalone company, which will begin immediately and progress over the next 12 to 18 months. The spinoffs of BHGE and GE Healthcare are part of GE’s efforts announced last fall to sell $20 billion worth of assets. The Big Unknowns for World’s Balancing Act of Supply and Demand Trent Jacobs, Digital Editor Last year was a dynamic one for both oil producers and consumers. For much of 2017, oil prices headed north but consumption still outgrew daily production—even as those totals were rising too. The net effect was seen as a positive for what has been a chaotic oil market in recent years. However, an annual report from BP’s economic group that studies market forces for the company has raised questions about what could disrupt this tenuous balance going forward. Driven by rising but still relatively low prices, 2017 saw world oil demand increase by an impressive 1.7 million B/D. This 1.8% increase stands above the 10-year average of 1.2% and marks the third year in a row that these figures have seen an uptick. Equinor Releases Subsurface and Production Data From NCS Field Stephen Whitfield, Senior Staff Writer For the first time, the general public will have complete access to the subsurface and production data from a field on the Norwegian continental shelf (NCS). Equinor announced that it will disclose the data from Volve, a shallow-water oil field located in the southern part of the Norwegian North Sea approximately 125 miles west of Stavanger. Following its startup in February 2008, Volve’s production lasted for approximately 8 years. It was originally scheduled for 3 to 5 years of operation. At its peak, the field produced 56,000 BOPD, and a total of 63 million bbl of oil were produced before the field’s shutdown in September 2016. Equinor said that one of the goals of the data release is to allow students from relevant fields of study to train on real data sets. Equinor, ExxonMobil Rack Up More Brazilian Pre-Salt Acreage Matt Zborowski, Technology Writer Equinor secured interests in two of three blocks awarded 7 June during Brazil’s 4th pre-salt bid round, further expanding its footprint in the growing offshore province alongside ExxonMobil, Shell, BP, and Chevron. Three of four blocks were awarded overall, each of which will be operated by Petrobras. The state-owned firm has a right of first refusal to petition the government to operate all pre-salt blocks offered. The round received some $800 million in signing bonuses and $190 million in planned exploration investments. The Norwegian firm took a stake in the highly coveted Uirapuru block in the Santos Basin with partners ExxonMobil and Petrogal Brasil. Petrobras exercised its right to enter the consortium and will be the operator with a 30% interest. Equinor and Exxon-Mobil will each have a 28% stake, with Petrogal Brasil holding the remaining 14%.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 186005, “An Innovative Approach Toward Improving the Relationship Between Flow-Zone Indicators With Lithofacies: A Case Study in a Carbonate Oil Field in the Middle East,” by N.S. Hashim, A.F. Zakaria, and N.A. Ishak, Petronas, prepared for the 2017 SPE Reservoir Characterization and Simulation Conference and Exhibition, Abu Dhabi, 8–10 May. The paper has not been peer reviewed. The F field in the Middle East currently has more than 40 producing wells in the center of the structure. The uneven well distribution limits the understanding of 3D reservoir characterization, particularly in the flank areas. A fit-for-purpose integrated reservoir-characterization study was carried out. The exercise, outlined in the complete paper, confirms the heterogeneity within B formation (the primary oil reservoir within F field), and it captures the changes in reservoir quality laterally and vertically. Introduction F field is located in the northeastern part of the Arabian Peninsula. F field is a low-relief anticlinal structure aligned northwest/southeast, approximately 31 km long and 10 km wide. B formation consists of carbonate-ramp depositional settings, and has an average thickness of 200 m. Multiple development wells were drilled as part of its development plan, and its first oil production was achieved 3 years ago. Issues with reservoir characterization have arisen because of the uneven well distribution, especially in the flank area. Furthermore, only one conventional core with good recovery was available for Reservoir B, which makes it somewhat difficult to delineate the internal architecture of the carbonate ramp. B Formation Stratigraphic Interval B formation subreservoirs include Upper B (UB), Middle B (MB), and Lower B (LB); the MB and LB subreservoirs contain most of the hydrocarbon deposits. UB does not contain any hydrocarbons and is believed to be tight on the basis of log information. Each subreservoir was divided into sub-units (UB-1 and UB-2; MB-1, MB-2, and MB-3; and LB-1, LB-2, and LB-3) on the basis of pressure and fluid information. One conventional core was taken with a total length of 100 m and total core recovery of 97%. This conventional core covers the Middle B to Lower B subunits. Full-core analysis study was conducted on this conventional core, which includes routine geological analysis, routine core analysis (RCA), special core analysis, and digital rock analysis. Lithofacies Analysis The study identified seven lithofacies. Bioclastic Mudstone (BM ). BM consists of a mostly micrite matrix. It is light gray to pale brown and is moderately bioturbated. In terms of reservoir characteristics, this lithofacies is poor, with no visible porosity. BM is usually deposited in an open marine slope. Bioclastic Wackestone (BW). As with BM, BW also consists of a micrite matrix. Carbonaceous wispy seams, solution seams, and stylolization are also common in this lithofacies. BW is characterized as tight, with no visible porosity. Its measured porosity ranges from 4 to 21%, with average porosity of only 10% and a permeability range between 0.1 and 7.6 md. BW is likely located in the shallow marine middle ramp.

Technology Focus Not too long ago, horizontal drilling revolutionized the petroleum industry. Emerging logging-while-drilling and geosteering technologies helped bring about multilateral, maximum-contact, and smart-completion wells, allowing reservoirs to be developed and produced much more efficiently and economically. This increased recovery, thus boosting reserves. In the process, formation evaluation plays a critical role in determining whether a producer or an injector is successful. More recently, efficient mass horizontal drilling and optimized multistage massive fracturing have turned traditionally nonreservoir source rock into sweet spots of energy strategy on a global scale. Production from unconventional reservoirs in the last decade has dramatically changed the petroleum industry, and this movement continues to evolve. Developing unconventional resources demands unconventional thinking, mainly because of the many challenges involved in evaluating tight source rocks. The two fundamental petrophysical properties, pore structure and wettability, are completely different between conventional reservoirs and unconventional source rocks. What may be next on the horizon? It is estimated that methane hydrates contain much more gas than shale plays, and, understandably, many countries are keen to explore this vast potential. As per recent news releases, China Geological Survey geoscientists and China National Petroleum Corporation engineers may have made a great technology breakthrough by being able to test significant hydrate-gas production in the South China Sea. If this is sustainable, exploring hydrate gas may be the next game changer for the energy industry. Evaluating hydrate gas formations would not be easy, however, and producing them safely, economically, and in an environmentally friendly way would be very challenging. But, I have high hopes that future technologies will be able to resolve these challenges to produce hydrate gas conventionally so it can be used to improve living standards. Recommended additional reading at OnePetro: www.onepetro.org. SPE 182448 The Petrophysics Role of Low-Resistivity Pay Zone of Talang Akar Formation, South Sumatera Basin, Indonesia by Z. Holis, SKK Migas, et al. SPE 183883 Using Digital Rock Modeling To Estimate Permeability and Capillary Pressure From NMR and Geochemical Logs by Hao Zhang, Baker Hughes, et al. SPE 183800 An Innovative Approach for Integrated Characterization and Modeling of a Complex Carbonate Reservoir by F. Ben Amor, Schlumberger, et al.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 178996, “Removing Formation Damage From Fines Migration in the Putumayo Basin in Colombia: Challenges, Results, Lessons Learned, and New Opportunities After More Than 100 Sandstone-Acidizing Treatments,” by Wildiman Reinoso, Fredy Torres, and Manuel Aldana, Grantierra, and Pablo Campo, Emilce Alvarez, and Erika Tovar, Halliburton, prepared for the 2015 SPE International Conference and Exhibition on Formation Damage Control, Lafayette, Louisiana, USA, 24–26 February. The paper has not been peer reviewed. To date, more than 100 sandstone-acidizing treatments have been performed in several Colombian oil fields, targeting the Villeta and Caballos Formations in the Putumayo Basin. Fines migration has been the main damage mechanism treated with this type of chemical stimulation. This paper summarizes a wide variety of sandstone-acid-stimulation case histories, highlighting aspects such as mechanical conditions and operational practices. Introduction The Putumayo Basin is located in south-ern Colombia. The Putumayo Basin shows a stratigraphic sequence containing Early Cretaceous (marine) to Miocene/Pliocene sediments (fluvial). Fig. 1 illustrates the location of the Putumayo Basin. Sand Villeta Formation The T Sand samples examined are fine-to medium-grained sandstones. They are composed primarily of quartz grains cemented primarily with quartz overgrowths and authigenic clays. Rare-to-minor cements include solid hydro-carbon, pyrite, and dolomite. X-ray-diffraction (XRD) analyses show that all of the sandstone samples are composed primarily of quartz and clay minerals. Feldspars are absent from all but one sample. Given that virtually all of the framework grains are quartz, with possibly minor argillaceous grains, the sand-stone is classified as quartzarenites. Scanning-electron-microscope (SEM) photographs show authigenic kaolinite filling intergranular zones and possibly replacing grains. Caballos Formation Samples in this formation are all sand-stones. Estimated average grain size ranges from very fine sand to medium sand. The framework grain suite is dominated by quartz. The grains are cement-ed primarily by quartz overgrowths and authigenic clays. XRD determined that all of the samples are composed primarily of quartz and clay minerals. Feld-spars are rare to absent from these sand-stones, confirming that virtually all of the framework grains are quartz and the sandstones should be classified as quartzarenites. Clay-mineral content averages 7.8%, with illite and mixed-layer illite/smectite more common than kaolinite. SEM photos show that these clays are authigenic.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 18296, “Tapping the Difficult Oil and Enhancing Reservoir-Development Strategy To Maximize Recovery From a Mature Waterflood Giant Carbonate Field in the Middle East: Arab C Reservoir, Dukhan Field, State of Qatar,” by Mohamed Naguib Bin Ab Majid, Carlos Troconiz, Mohammed Nedham Al-Shafei, Gheorghe Luca, and Ariel Cachi, Qatar Petroleum, prepared for the 2015 International Petroleum Technology Conference, Doha, Qatar, 7–9 December. The paper has not been peer reviewed. Copyright 2015 International Petroleum Technology Conference. Reproduced by permission. After 70 years of production, more than 30% of the Arab C reservoir stock-tank original oil in place has been recovered through various mechanisms including natural depletion, waterflooding, gas lift implementation, and horizontal-well development. Extending production into future years requires a strategic approach focusing on innovative development to target the remaining oil saturation. Integration of a recently acquired, high-resolution 3D-seismic survey complements the data available for subsurface description and characterization, positively affecting reservoir-model history-matching metrics. Introduction The large, mature Dukhan field is located onshore Qatar, approximately 80 km west of Doha. The Arab C reservoir interval is a carbonate anticlinal structure lying 5,500 to 7,000 ft below the surface. Areally, the Arab C reservoir has been divided into four structural elements from north to south (i.e., Khatiyah, Fahahil, Jaleha, and Diyab). The first three sectors comprise the continuous oil-bearing extent of the reservoir, while Diyab is water-bearing on the basis of results from wells drilled to date (Fig. 1). Arab C is an undersaturated-oil reservoir. The original oil column ranged from 1,400-ft thickness in the Khatiyah sector to 400 ft in the Jaleha sector. It has a weak to moderate connected aquifer lying below the oil column. Arab C development started with vertical wells, initially completed openhole. Increase in water production led to a well-completion-scheme change; vertical wells were then completed cased-hole and perforated selectively. Horizontal drilling commenced in 1992 to improve recovery and enhance production. As the water front from injection progressed, gas lifting in Arab C was initiated in 2003 to continue producing the high-water-cut wells. Currently, 60% of the Arab C producers are flowing under gas lift assistance. Reservoir Description Arab C is a heterogeneous organization of limestone and dolomite lithologies deposited on a shallow-water Jurassic ramp system. Hydraulically, the 80-ft-thick interval represents a net-work of grainstone conductors compartmentalized by muddy carbonate baffles resulting in layer-constrained dynamic behavior. Lateral ranges of 1 to 4 km for baffling thin beds support a localized layer-constrained dynamic behavior and a high degree of vertical heterogeneity, though communication pathways are impacted by sporadic occurrences of cross-cutting conductive and resistive faults. Reservoir porosity is 15 to 20%, and the average permeability is approximately 150 md, but this varies widely on the basis of reservoir zone.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 174946, “The Role of Induced Unpropped Fractures in Unconventional Oil and Gas Wells,” by M.M. Sharma and R. Manchanda, The University of Texas at Austin, prepared for the 2015 SPE Annual Technical Conference and Exhibition, Houston, 28–30 September. The paper has not been peer reviewed. The term induced unpropped (IU) fractures refers to fractures created around the main propped fracture that are too small to accommodate any proppant. These could include natural fractures and microfractures induced along bedding planes or along other planes of weakness. On the basis of production data, diagnostic methods, and field observations, it is becoming increasingly clear that IU fractures created during the hydraulic-fracturing operation play a critical role in determining the success of fracture treatments. Introduction There has been a debate about whether certain shales are naturally fractured. The classic example of this is the Barnett Shale. Many authors have suggested that the Barnett Shale is highly naturally fractured, whereas others have argued that field observations in the Barnett can be explained on the basis of geologic lithofacies and heterogeneity. Observations made on cores clearly indicate the presence of fractures. Mineralization on the faces of these fractures indicates that they are not drilling-induced fractures but are instead native to the Barnett. Similar questions and discussions have arisen about the role of natural and induced fractures in other shale plays. One reason that it is often difficult to resolve questions about natural fractures in shales is the extreme level of heterogeneity commonly observed in many types of shale. Differences in lithology and the highly laminated nature of many types of shale are apparent when viewing cores from source rocks such as the Eagle Ford Shale. In some instances, the boundary between the lithologically distinct layers is sharp and well-defined, but, in other instances, it is diffuse and displays its own characteristic lithologic gradation. Boundaries between lithologically distinct layers can often act as planes of weakness along which fractures can develop under stress.