Automated Approaches Determine Solids Content in Drilling and Completions Fluids

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201368, “Automated Solids-Content Determination in Drilling and Completions Fluids,” by Sercan Gul, SPE, Ali Karimi Vajargah, and Eric van Oort, SPE, The University of Texas at Austin, et al., prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, 5–7 October. The paper has not been peer reviewed. Monitoring of low- and high-gravity-solids (LGS and HGS) content and maintaining these at ideal levels is essential for optimal drilling fluid performance, efficient hole cleaning and equivalent-circulating-density management, and prevention of failures of surface and downhole equipment during drilling. LGS and HGS monitoring in the field is currently accomplished using the API retort-kit measurement, which has certain drawbacks and is difficult to automate. In the complete paper, two new approaches are investigated to automate the LGS and HGS content measurements of drilling fluids, which potentially can replace the retort test. Introduction The conventional way to characterize LGS and HGS in the field is by using a retort-kit measurement specified in API Recommended Practices 13B-1 and 13B-2. The longevity of these tests is testament to the effectiveness of the API standards and the tests themselves in providing useful and practical field guidance. Despite their evident success, however, various downsides exist in current solids-content-testing methods. Retort-kit measurements present the following issues: - Difficulty in obtaining accurate and repeatable test results - Safety issues associated with laboratory testing at elevated temperatures (over 930°F) - Interpretive bias issues associated with test results, including the potential for deliberate manipulation of these results - Difficulty in automating the retort test for improved efficiency and safety The authors’ opinion is that automating antiquated API test protocols is not a useful practice. They write that a clean-slate approach would be better, in which a determination is made whether solids-content information can be provided in a novel and meaningful way using methods that deviate from standard API recommended practices. In the complete paper, the authors investigate a machine-learning (ML) and data-analytics method for this purpose in combination with a novel inline X-ray fluorescence (XRF) measurement method.

Strategy Targets Risk Management for CO2 Waterless Fracturing

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30437, “Risk Management and Control for CO2 Waterless Fracturing,” by Siwei Meng, Qinghai Yang, SPE, and Yongwei Duan, PetroChina, et al., prepared for the 2020 Offshore Technology Conference Asia, originally scheduled to be held in Kuala Lumpur, 2–6 November. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. Given shortages and uneven distribution of water resources in China, efforts must be made to develop waterless fracturing techniques. The fluid experiences high pressures and low temperatures during carbon dioxide (CO2) waterless fracturing operations, which can lead to accidents and environmental pollution. In the complete paper, a safety-management approach and a contingency plan for such operations are developed. At the time of writing, this CO2 waterless fracturing methodology has been completed successfully more than 20 times. Surface Process Work Flow of CO2 Waterless Fracturing The basic process of a CO2 waterless fracturing operation is shown in Fig. 1. First, several CO2 storage tanks are connected in parallel. The booster, sealed blender, fracturing pump (all mounted on trunks), and wellhead equipment are connected. The measuring trunk communicates with each vehicle to monitor operation status. Proppant is put into the sealed blender, into which liquid CO2 is injected for pre-cooling. Pump testing is conducted on the high-pressure line and the wellhead and the low-pressure liquid supply line is pressure-tested. Operation does not proceed until pressure-testing results are positive. Afterward, liquid CO2 is injected into formations to fracture them and, moreover, extend created fractures. The sealed blender is enabled to inject prop-pants, and displacement begins after the end of proppant injection. Finally, a series of tasks, including well shut-in for soaking and flowback, is carried out successively.

Case Study: Single-Aqueous-Phase Retarded Acid Performance Offshore Sarawak

The purpose of acid stimulation of carbonate formations is to increase production. The essential component for these stimulation fluids is the carbonate-dissolving agent, which creates conductivity channels connecting the reservoir with the wellbore. Controlling the reactivity of hydrochloric acid (HCl), the most-used dissolving agent due to its high dissolving capacity, wide availability, and low unit cost, is the most viable approach to successfully stimulate a high-temperature carbonate reservoir. It is essential to retard the HCl-carbonate rock reaction to achieve the optimum balance between total fluid used and enhanced well production. It is well documented that the conventional emulsified acid exhibits high friction pressure, is cumbersome to prepare, and performs with sensitivity to a multitude of parameters. These drawbacks have prevented the industrywide adoption of this method. The recently developed single-aqueous-phase retarded acid (SAPRA) designed for primarily 15–25% HCl solutions represents a significant step forward. The first successful field implementation of SAPRA took place offshore the Malaysian state of Sarawak in early 2021. At Sarawak, the HCl reactivity was regulated and retarded by a single potent low- dosage additive, which is compatible with selected acid corrosion inhibitors, nonemulsifiers, H2S scavengers, other commonly used additives, and if necessary, friction reducers. Improving Acid Stimulation Efficiency The technical approach behind SAPRA is based on chemical technology that enables the reduction of the reaction rate and allows the control of the diffusion/mass transfer mechanism. This is key in designing the acid treatment to optimize chemical program cost and well production and has been extensively studied (Al Moajil et al. 2020; Czupski et al. 2020; Daeffler et al. 2018; and Abdrazakov et al. 2018). The technology was developed utilizing a surface barrier concept where transiently adsorbed retarder molecules adhere to a carbonate surface and thus, delay the hydrogen ion carbonate reaction over a range of acid concentrations and operating temperatures. Due to the complexity of the chemical interactions among all the additives in the acid fluid system, the selected additives must be screened to ensure mutual compatibility before conducting performance testing such as corrosion rate, calcite solubility capacity characterization, and coreflow measurements. Incompatible chemistry could lead to severe corrosion issues such as the examples shown in Table 1.

Guest Editorial: Unconventional Development Approaches Health Check, and Where We Have To Go

The direction of unconventional developments has been a roller-coaster ride, not only in the realms of financing and profitability, but very much in the technical execution of the well construction and the completion phases, too. This is particularly the case for those aspects relating to the completion and hydraulic fracturing operations. There are few parties, I believe, that would disagree that the drilling com-munity rapidly delivered an extremely coherent and efficient learning curve, something that the completion/fracturing discipline has unfortunately been much slower to achieve. This is not in the least surprising. Effectively extending conventional technologies and focusing on key requirements (i.e., getting from point A to point B) worked well for drilling teams. In a commendable and efficient manner, they were able to readily deploy and incrementally learn in an almost linear fashion. This achieved remarkable delivery records across all unconventional plays. Completions however, namely hydraulic fracturing, has been a very different journey and involves solving a very different problem, one with many more variables, inherent complexities, and multiple degrees of freedom. With each unconventional play potentially being distinct (just as with drilling), these differences can, however, extend to impactful areal trends and features within the plays, as well as subtle variations along individual lateral wellbores. For example, unlike drilling, the form (and even sequence) of an offset wellbore completion can easily affect the completion operations in the current wellbore. It is quite likely that much of the initial misdirection of energy and effort resulted from an overenthusiastic application of conventional planar fracturing technology and knowledge to the unconventional environment. Perhaps the initial lack of effective diagnostic tools and approaches played a role, something that appears to have been understandably addressed in recent years. However, there was also a likely inherent engineering bias in the industry’s fracturing staff engineers. The bulk of the industry engineers had entered unconventionals off at least 2 decades of well understood, well defined, and highly effective physics-based analysis of conventional planar fracturing operations. Indeed, in some areas this fallacy continues. For example, proppant selection is ostensibly performed based on long-established criterion set in place in the 1970s and 1980s, and wholly appropriate to planar fracturing. Whereas the reality is that proppant plays multiple very different roles in unconventionals, bridging, plugging, wedging, diverting, etc. This has led to a “tearing up of the rule book” situation within the sector (that is ongoing) as poorer-quality sands and micro-/nanoproppants find applicability, as well as quality ceramics for a strategic place in the fracture. Yet, you may ask any frac engineer to select proppant for unconventionals and they will almost immediately request data on performance at 2 lb/ft2, as though we are flowing through proppant packs across the entire created geometry. This significantly enhanced level of complexity has led to a general failure of the linear model in terms of effectiveness in progressing optimum completion solutions. As a result, the early years of unconventional completion learning were largely “lost” in this linear way.

E&P Notes (November 2021)

TotalEnergies Drills Dry Hole Offshore Suriname TotalEnergies has plugged and abandoned its Keskesi South-1 on Block 58 offshore Suriname after encountering noncommercial quantities of hydrocarbons. Keskesi South-1 was drilled about 6.2 km from the discovery well Keskesi East-1. “The first appraisal well at Keskesi was a substantial stepout designed to assess the southern extent of the feature,” said Tracey K. Henderson, senior vice president, exploration at APA, a partner in the block. “This location had the potential to confirm a very large resource in place if connected to the reservoir sands in the discovery well. However, suitable reservoir-quality sands were not developed in the Campanian target at the Keskesi South-1 location. Data gathered from the well will be used to calibrate our geologic model and inform the next steps for Keskesi appraisal.” Semisubmersible Maersk Developer has moved to the Sapakara South-1 well, where it will conduct a flow test of the previously announced appraisal success. Following the completion of the Sapakara South-1 flow test, the exploration program will continue with the spud of the Krabdagoe prospect just to the east of Keskesi. Drillship Maersk Valiant is currently drilling Bonboni, the first exploration prospect in the northern portion of Block 58. Both rigs are operated by TotalEnergies. APA Suriname holds a 50% working interest in the block, with TotalEnergies, the operator, holding the remaining 50% stake. Harbour Abandons Falklands Plan, Will Exit Basins in Brazil, Mexico Harbour Energy (formed with the merger of Premier and Chrysaor) announced it will not proceed with the Sea Lion development in the Falkland Islands. The producer will instead focus on the successful integration of Premier Oil’s assets. Sea Lion, discovered in 2010 by Rockhopper, is estimated to hold more than 500 million bbl, but development startup has been stuck in neutral. Rockhopper intends to pursue the project and will talk with other operators about participating in the wake of Harbour’s exit. Harbour also revealed plans to exit exploration license interests in the Ceará basin in Brazil and the Burgos basin in Mexico. The operator said it wants to reinvest in lower-risk opportunities in regions where the company already has a presence. Harbour is the largest UK-listed independent oil and gas producer with most of its assets located in Southeast Asia and the North Sea. BP Starts Production at Thunder Horse Expansion BP confirmed it started oil and gas production at its Thunder Horse South Phase 2 offshore expansion project in the US Gulf of Mexico. The project comprises two subsea drill centers in 6,350 ft of water. They are connected to BP’s Thunder Horse production and drilling platform by 10-in. dual flowlines and are expected to add up to 25,000 B/D of production. The scope of the expansion will see a total of eight wells brought online, adding as much as 50,000 B/D of production. “This is another significant milestone for BP, completing the delivery of our planned major projects for 2021,” said Ewan Drummond, BP senior vice president, projects, production, and operations. “This project is a great example of the type of fast-payback, high-return tieback opportunities we continue to deliver as we focus and high-grade our portfolio.” BP operates Thunder Horse with a 75% stake; ExxonMobil holds 25%. The Phase 2 expansion project is part of BP’s plans to grow its Gulf of Mexico oil and gas production to around 400,000 B/D by the middle of the decade. ReconAfrica Granted Extension in Namibia Reconnaissance Energy Africa (ReconAfrica) and its joint venture partner NAMCOR (the state oil company of Namibia) said the Ministry of Mines and Energy has granted a 1-year extension of the first renewal period to 29 January 2023, relating to the approximate 6.3-million-acre (PEL) 73 exploration license, due to the impacts of the pandemic. ReconAfrica holds a 90% interest in PEL 73 covering portions of northeast Namibia. The exploration license covers the entire Kavango sedimentary basin. Eni Achieves First Oil at Cabaça North off Angola Eni has started production from the Cabaça North development project in Block 15/06 of the Angolan deep offshore, via the Armada Olombendo FPSO vessel. The development, with an expected peak production rate in the range of 15,000 B/D, will increase and sustain the plateau of the FPSO with an overall capacity of 100,000 B/D. This is the second startup achieved by Eni Angola in 2021, after the Cuica early production achieved in July. A third startup is expected within the next few months, with the Ndungu early production in the western area of Block 15/06. Block 15/06 is operated by Eni Angola with a 36.84% share. Sonangol Pesquisa e Produção (36.84%) and SSI Fifteen Limited (26.32%) are joint venture partners. Further to Block 15/06, Eni is the operator of exploration blocks Cabinda North, Cabinda Centro, 1/14, and 28, as well as of the New Gas Consortium (NGC). In addition, Eni has stakes in the nonoperated blocks 0 (Cabinda), 3/05, 3/05A, 14, 14 K/A-IMI, and 15, and in the Angola LNG project. Gas Production at Groningen To Cease Next Year The Netherlands plans to end gas production at the large Groningen field next year, the Dutch government recently confirmed. Output at Groningen will be cut by more than 50% to 3.9 Bcm in the year through October 2022, which will be the last year of regular production. The recent runup in natural gas prices has not impacted the state’s plans. The Dutch government originally announced Groningen would shutter by mid-2022 to limit seismic risks in the region but left the possibility of emergency production in the event of extreme weather conditions from select sites. To keep these sites operational, around 1.5 Bcm of gas will be produced on a yearly basis, until a main gas storage site can be switched to the use of imported low-calorific gas instead of the high-calorific gas Groningen delivers. The government wants the conversion to happen quickly, but originally thought it would not happen until between 2025 and 2028. Discovered in 1959, the Groningen field is run by Shell and ExxonMobil joint venture NAM. BP Turns on the Taps at Matapal BP Trinidad and Tobago achieved first gas at its Matapal subsea development offshore Trinidad. The project comprises three wells which tie back into the existing Juniper platform. Matapal is located about 80 km off the southeast coast of Trinidad and approximately 8 km east of Juniper, in a water depth of 163 m. Equinor Spuds Egyptian Vulture Well off Norway Equinor has started drilling operations on the Egyptian Vulture exploration well located offshore Norway. According to well partner Longboat Energy, the drilling of the Egyptian Vulture prospect is being undertaken by Seadrill semisubmersible West Hercules. The well is expected to take up to 7 weeks to drill. The exploration probe is targeting gross mean prospective resources of 103 million BOE with further potential upside to bring the total to 208 million BOE on a gross basis. The chance of success associated with this prospect is 25% with the key risk related to reservoir quality and thickness. Longboat has gained access to a drilling program of seven exploration wells in Norway through agreements with three separate companies. Earlier, Vår Energi started drilling the Rødhette exploration well off Norway, the first in a series of seven wells where Longboat will participate as a nonoperator. SBM Secures Large FPSO Financing SBM Offshore has completed the project financing of FPSO Sepetiba for a total of $1.6 billion—the largest project financing in the company’s history. The financing was secured by a consortium of 13 international banks with insurance from Nippon Export, Investment Insurance (NEXI), and SACE SpA. China Export & Credit Insurance Corporation (Sinosure) intends to join this transaction by the end of the year and will replace a portion of the commercial banks’ commitments. Sepetiba is owned and operated by a special-purpose company owned by affiliated companies of SBM Offshore (64.5%) and its partners (35.5%). The vessel has a processing capacity of up to 180,000 B/D of oil, a water-injection capacity of 250,000 B/D, associated gas treatment capacity of 12 MMcf/D and a minimum storage capacity of 1.4 million bbl of crude oil. Sepetiba will be deployed at the Mero field in the Santos Basin offshore Brazil, 180 km offshore Rio de Janeiro. The vessel will be spread-moored in approximately 2000 m water depth. The Libra Block, where the Mero field is located, is under a production-sharing contract to a consortium (PSC) comprising operator Petrobras (40%), Shell Brasil (20%), TotalEnergies (20%), CNODC (10%), and CNOOC Limited (10%). The consortium also has the participation of state-owned Pré-Sal Petróleo SA (PPSA) as manager of the PSC.

Technology Focus: Hydraulic Fracturing Modeling (November 2021)

In the past decades, the success of unconventional hydrocarbon resource development can be attributed primarily to the improved understanding of fracture systems, including both hydraulically induced fractures and natural fracture networks. To tackle the fracture characterization problem, several recent papers have provided novel insights into fracture modeling technique. Because of the complex nature and heterogeneity of rock discontinuity, fabric, and texture, the fracture-modeling process typically suffers from limited data availability. Research shows that modeling results reached without interrogation of high-resolution petrophysical and geomechanical data can mislead because the fluid flow is actually controlled by fine-scale rock properties. A more-reliable fracture geometry can be obtained from an enhanced modeling process that preserves the signature from high-frequency data. Advanced techniques to model fracturing processes with proppant transportation and thermodynamics require even more-sophisticated simulation and computation power. When the subsurface is too puzzling to be described by a physical model and existing data, machine learning and artificial intelligence can be adapted as a practical alternative to interpret complex fracture systems. Taking a discrete fracture network (DFN) as an example, a data-driven approach has been introduced to learn from outcrop, borehole imaging, core computed tomography scan, and seismic data to recognize stratigraphic bedding, faults, subseismic fractures, and hydraulic fractures. Input data can be collected by hand, 3D stereophotogrammetry, or drone. When upscaling DFN into a coarse grid for reservoir simulation, deep-learning techniques such as convolutional neuron networks can be used to populate fracture properties into a dual-porosity/dual-permeability model approved to yield high accuracy compared with a fine-grid model. Furthermore, the new techniques greatly extend the application of fracture modeling in the arena of the energy transition, such as in geothermal optimization. Recommended additional reading at OnePetro: www.onepetro.org. SPE 203927 - Numerical Simulation of Proppant Transport in Hydraulically Fractured Reservoirs by Seyhan Emre Gorucu, Computer Modelling Group, et al. SPE 202679 - Deep-Learning Approach To Predict Rheological Behavior of Supercritical CO2 Foam Fracturing Fluid Under Different Operating Conditions by Shehzad Ahmed, Khalifa University of Science and Technology, et al. SPE 203983 - A 3D Coupled Thermal/Hydraulic/Mechanical Model Using EDFM and XFEM for Hydraulic-Fracture-Dominated Geothermal Reservoirs by Xiangyu Yu, Colorado School of Mines, et al.

Sustainable Recovery: Signs of Recovery?

The 2021 SPE Annual Technical Conference and Exhibition (ATCE) was held in September as a hybrid (in-person and virtual) event in Dubai with more than 6,000 participants, with the health and safety of the participants being our highest priority. While the number of attendees is lower than in previous years, there was a general feeling that we may finally be getting out of the pandemic situation, after 18 months of a complete trans-formation of the way we work, communicate, and move. Thanks to the Conference Chair Ali Al Jarwan, CEO of Dragon Oil; Program Committee Chair Fareed Abdulla AlHashmi, COO of Dragon Oil; and the ATCE Executive and Program committees for organizing an excellent event under the theme of “The New Oil and Gas Journey: Agility, Innovation, and Value Creation.” The conference included 80 technical sessions, six plenary and panel sessions, and eight special sessions, spanning digitalization, electrification, sustainability, and emerging themes. Our appreciation goes to the sponsors, the exhibitors, the presenters, the volunteers, and the SPE staff. Dubai and the UAE, 1 week before the 2020 World Expo, were great hosts. Congratulations to the winners of the SPE (and AIME) International, Regional, and Student awards (https://jpt.spe.org/spe-honors-2021-international-award-recipients-during-annual-meeting). Many of them were able to travel to Dubai to receive their recognition. The Startup Village Awards, organized in collaboration with Rice University, was also well attended, and the winners were recognized (https://jpt.spe.org/2021-atce-startup-village-competition-winners-announced). The dynamism of the city of Dubai and the country of UAE and their capacity to project themselves in the future with a unique 50-year strategical timeframe that spans the period 2021–2071 never cease to amaze me. The world, including developing economies, has expanded significantly the COVID-19 vaccination campaign, reaching more than 6 billion doses administered, and nearly half of the world has received at least one dose of vaccination as of early October. The “green list” of countries deemed safe for travel is expanding after a summer that has seen a major impact of the COVID-19 Delta variant. Oil and gas demand is recovering for sectors such as transport and industry, even though the airlines may not see pre-pandemic levels of activity before 2025. Massive amounts of public funding injected to fuel the world’s economic recovery have been announced in Europe, the US, and Asia, adding up to trillions of dollars. However, economic recovery from the pandemic will take time, as there is a major backlog in global manufacturing activities impacting consumer markets and creating inflationary pressures.

A New Recipe for Friction-Reducer Suppliers: Polymer Plus Frac Water, Minus the Cost

The argument for making friction reducer on site is simple: only one truck is required to deliver dry polymer vs. three loads required for the same amount of liquid additive. For Downhole Chemical Solutions (DCS), reducing the number of trips and the amount of chemicals needed to create a stable liquid by mixing it as needed on site reduces the average cost of a gallon of friction reducer by around 30%, said Mark Van Domelen, vice president of technology for DCS. “The business is very cutthroat and competitive on the pricing of polyacrylamide. We can reduce the cost further on friction reducer,” using dry polymer, he said. Polyacrylamide is generally described as the key component in friction reducers. Suppliers also add some ingredients to create a stable liquid and others that are supposed to improve performance. When DCS delivers dry polymer to a well pad to mix it on-site, the only other ingredient is water provided by the customer. It has been a winning strategy change for the private company; it has grown rapidly, even during last year’s slump. DCS increased the number of mixing units from one to 16, and dry polymer sales have grown from 10% to 90%, Van Domelen said. One of the company’s customers is John Blevins, the chief operating officer for Houston-based Hibernia Resources III and an early adopter who was a lead author of a paper on making friction reducer on site while fracturing (SPE 204176). Blevin, who uses the words “friction reducer” and “polymer” interchangeably, is the rare C-level executive who likes to manage operations from a frac van at a company that normally completes one pad at a time. The polymer is polyacrylamide. When Blevin works with DCS on a well, he purchases it directly from one of the few chemical companies that will produce the polymer based on his specifications. The price on the DCS invoice will be a price per pound that covers the cost of the polymer and the service. At Hibernia, a small private-equity and employee-owned company, there is a powerful incentive to pay close attention to the details. “When we spend a nickel, that nickel is divided among us at some point in time. If we are efficiently frugal, we are going to be better off in the long run,” Blevins said. The paper, which was presented at the Unconventional Resources Technology Conference (URTeC), included a chart showing stage-by-stage costs, with the average cost for dry stages ranging from 27% to 31% lower than similar stages that were fractured using liquids. The simplicity of the mix is a plus for Blevins whose company is especially focused on how chemicals are likely to react downhole. “We did a 6-month study before we pumped anything in the ground to make sure we had the right combination” of fracturing additives, he said. “We do study nearly every well and every landing zone to ensure the chemicals used are compatible.”

Machine-Learning Upscales Realistic Discrete Fracture Simulations

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 203962, “Upscaling of Realistic Discrete Fracture Simulations Using Machine Learning,” by Nikolai Andrianov, SPE, Geological Survey of Denmark and Greenland, prepared for the 2021 SPE Reservoir Simulation Conference, Galveston, Texas, 4–6 October. The paper has not been peer reviewed. Upscaling of discrete fracture networks to continuum models such as the dual-porosity/dual-permeability (DP/DP) model is an industry-standard approach in modeling fractured reservoirs. In the complete paper, the author parametrizes the fine-scale fracture geometries and assesses the accuracy of several convolutional neural networks (CNNs) to learn the mapping between this parametrization and DP/DP model closures. The accuracy of the DP/DP results with the predicted model closures was assessed by a comparison with the corresponding fine-scale discrete fracture matrix (DFM) simulation of a two-phase flow in a realistic fracture geometry. The DP/DP results matched the DFM reference solution well. The DP/DP model also was significantly faster than DFM simulation. Introduction The goal of this study was to evaluate the effect of different CNN architectures on prediction accuracy for the DP/DP model closures and on the accuracy of DP/DP simulations in comparison with fine-scale DFM simulations. As a starting point, two CNN configurations were considered that have achieved breakthrough performance in image-classification tasks. The author adopted these architectures to the problem of learning the mapping between pixelated fracture geometries and the DP/DP model closures and indicated several key features in the CNN structure that are crucial for achieving high prediction accuracy. Mapping of fracture geometries requires significant effort, which limits the possibilities for creating large training data sets with realistic fracture geometries. The author, therefore, used the synthetic random linear fractures’ data set to train the CNNs and the fracture geometry from the Lägerdorf outcrop for testing purposes. It was demonstrated that an optimal CNN configuration yielded the DP/DP model closures such that the corresponding DP/DP results matched well the two-phase DFM simulations on a subset of the Lägerdorf data. The run times for the DP/DP model were a fraction of the time needed to accomplish the DFM simulations. Problem formulation is presented in a series of equations in the complete paper.

Low Polymer Retention Possible in Flooding of High-Salinity Carbonate Reservoirs

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202809, “Low Polymer Retention Opens for Field Implementation of Polymer Flooding in High-Salinity Carbonate Reservoirs,” by Arne Skauge, SPE, and Tormod Skauge, SPE, Energy Research Norway, and Shahram Pourmohamadi, Brent Asmari, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. Polymer flooding has been a successful enhanced-oil-recovery method in sandstone reservoirs for decades. Extending polymer flooding to carbonate reservoirs has been challenging because of adsorption loss and polymer availability for high-temperature, high-salinity (HT/HS) reservoirs. In this study, the authors establish that HT/HS polymers can exhibit low adsorption and retention in carbonate reservoir rock at ultrahigh salinity conditions. Introduction Retention is a key factor for polymer propagation and acceleration of oil production by polymer flooding. In the complete paper, the authors consider HT/HS applications for carbonate reservoirs. Synthetic polymers such as partially hydrolyzed polyacrylamide are not thermally stable at temperatures above 60°C. The thermal stability of the synthetic polymers can be improved by incorporating monomers. To evaluate the retention of polymer in reservoir rock, dynamic retention experiments were performed in the presence and absence of oil. In homogeneous rock, the presence of residual oil typically will reduce the retention proportional to the surface covered by the oil saturation. Strongly heterogeneous rock containing fractures also may have low retention because the fluid flow mainly may be through highly permeable fractures or channels and, consequently, only part of the porous medium will contact polymer. Retention in carbonate matrix displacement (homogeneous rock) was performed on outcrop Indiana limestone for reference, but most experiments were made on reservoir rock material. The polymer used is SAV 10. Experimental Methods The easiest and, in many cases, most-accurate method for quantifying retention in dynamic coreflow experiments is by material balance. This refers to the measurement of the polymer in the effluent. The injected amount minus the backproduced amount of polymer gives the loss caused by transport through the porous medium. The retention includes both adsorption of polymer onto the rock and dynamic loss as the result of mechanical entrapment such as molecular straining and concentration blocking. In most cases, the authors used a passive tracer injected with the polymer and applied two slugs. The first slug quantifies the retention by material balance, but the difference in effluent of the second slug minus the first slug also can give an alternative measurement of the polymer retention. Comparing tracer and polymer effluent concentrations from the second polymer slug quantifies the inaccessible pore volume (IPV). The experimental setup is illustrated in Fig. 1.