As production declines over time, the injection of fluids is required to enhance oil recovery and/or maintain the reservoir pressure. Whether applied at field startup or as a secondary recovery technique, waterflooding can boost oil recovery from less than 30% to 30–50%. The common problems associated with waterflooding include loss of injectivity, premature injector failure, and injection conformance. This can also lead to issues around insufficient voidage replacement, which can result in lower reservoir pressure and the production of fluid with a higher gas/oil ratio. In total field recovery, this ultimately means lower production and oil left untapped in the well. To remediate the issue of conformance, costly and often complex interventions and redrills were traditionally used to restore water-injection capability. Also, passive outflow-control devices have been used successfully to somewhat improve the fluid conformance from injection wells. However, they may fail in reservoirs with complex/dynamic properties including propagating/dilating fractures. Advanced Wells in Injection Wells There are a number of considerations when planning a water-injection completion, particularly around both the rock and fluid properties, as well as the credible risks that could occur, namely: - Uneven displacement of hydrocarbon - Fracture growth short-circuiting injectant-proximal wells - Fracture growth breaching caprock/basement seal - Crossflow, plugging, and solids fill Advanced completion options include deploying passive flow-control devices. For example, inflow-control devices (ICDs) are unable to react to dynamic changes in reservoir/well properties. This often requires production-logging-tool (PLT) logs, distributed temperature sensors, and/or tracers to be run and, if available, to apply the sleeve option. Alternatively, active (intelligent) completions, such as inflow-control valves, can be used, but they tend to be expensive and complicated and are limited to the number of zones. This technique also requires frequent analysis of data from the well to perform such actions. Tendeka, a global specialist in advanced completions, production solutions, and sand control, has developed FloFuse, a new and exclusively autonomous rate-limiting outflow-control device (AOCD) (Fig. 1). Using the analogy and inspiration of a home fuse box, which contains many individual fuses to control various parts of a building, the AOCD can control the excessive rate that passes through a specific section of a well, causing tripping once the threshold is reached. By almost shutting, i.e., significantly choking, the injection fluid into the fractures crossing the well, the AOCD autonomously prevents growth and excessive fluid injection into the thief/fracture zones and maintains a balanced or prescribed injection distribution. Like other flow-control valves, this device should be installed in several compartments in the injection well. Initially, devices operate as normal passive outflow control, but if the injected flow rate through the valve exceeds a designed limit, the device will automatically shut off. This allows the denied fluid to that specific compartment to be distributed among the neighboring compartments.

A long time ago, my mentor, Farooq Ali, wrote a thought-provoking paper on the unfulfilled promises of enhanced oil recovery (EOR). His essential summary: EOR had not lived up to its hype and full potential. There were more than a hundred methods and techniques proposed, but only a few had succeeded commercially. Fast-forward a few decades and into the new century, and the message and conclusions have not changed. EOR has definitely not lived up to its promise, especially from the big-picture perspective of daily oil production rates. Before the COVID-19 pandemic, the world was producing close to 100 million BOPD. Of this, only approximately 4 million BOPD was coming from EOR, and the bulk of this was from thermal. The numbers pale even when compared with shale oil, which has dominated US oil production during the past decade. So why has EOR failed so spectacularly? The answer is complex—mostly economic, less technical. It is difficult to compete against water (flooding), where the cost of the injectant is practically free. Compare this with EOR, where you have to inject something other than water—either heat, a gas or solvent, polymer, surfactant, or something exotic such as microbes. These techniques cost money and make EOR inherently expensive. They have become the Achilles’ heel of EOR. So, what is the message for those of us working in EOR? Make EOR cost-competitive, improve waterflooding, or join the sustainability bandwagon that is sweeping the world? That is the call of the hour, and for decades to come. While other EOR methods such as thermal and chemical will have a limited future, injection of carbon dioxide (CO 2 ) for EOR will be a win/win proposition. It provides a way to sequester CO 2 and produce additional oil at the same time. The oil revenues provide the “U” in “CCUS” (carbon capture, utilization, and storage) that will play a vital role in the removal of CO 2 . CCUS is considered by most to be an essential part of the climate-change portfolio of solutions. The papers in this feature are examples of CO 2 sequestration either with EOR or in saline aquifers. One provides the EOR and storage potential in the Norwegian continental shelf. Another is a case study of improving asset performance in marginal pay regions. The third is an example that capitalizes on the US government’s 45Q tax credits for incentivizing CO 2 injection. Our industry has been the custodian of subterranean reservoirs. We are the experts in managing and developing them. Why not use that expertise to find solutions for climate change by capturing and removing carbon and being part of the solution? Recommended additional reading at OnePetro: www.onepetro.org. SPE 200363 Economic Assessment of Strategies for CO 2 EOR and Storage in Brownfield Residual Oil Zones: A Case Study From the Seminole San Andres Unit by Bo Ren, The University of Texas at Austin, et al. OTC 30157 Effects of CO 2 /Rock/Formation Brine Parameters on CO 2 Injectivity for Sequestration by Muhammad Aslam Md Yusof, Universiti Teknologi Petronas, et al. SPE 202276 Is Chemical EOR Finally Coming of Age? by Eric Delamaide, IFP Technologies

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30277, “Twelve-Year Field Applications of Offshore Heavy Oil Polymerflooding From Continuous Injection to Alternating Injection of Polymer and Water,” by Guangming Pan, Lei Zhang, and Jianting Huang, CNOOC, 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. Polymerflooding has been considered a suitable method for reservoirs with viscosities up to 150 mPa · s. The authors of the complete paper verify that alternating injection of polymer and water in the Bohai Bay of China proved effective and economical for heavy oil fields, even offshore. This polymerflooding pilot of initially continuous, and then alternating, injection can provide a useful technical reference for similar reservoirs. Introduction Heavy oil reserves are abundant in the Bohai oil field of China. The development of the field has proved that the field with lower viscosity (less than 350 mPa · s) can be developed effectively by water-flooding, while the unconventional heavy oil reservoir with high viscosity has not formed a mature development mode. To better use interwell reserves, a pilot polymerflooding test has been conducted in the NN field since 2008. The cumulative production of nine wells in the surrounding area reached 10.80×10 4 m 3 , which confirmed that polymer fluid injection had a good displacement effect on unconventional high-viscosity crude oil. However, with the extension of continuous injection time, the pilot test area faced various problems. In order to explore the applicability of polymerflooding technology used in offshore unconventional heavy oil fields, the polymer-injection mode was studied on the basis of laboratory experimental data and field practice, and the polymer/water alternating injection mode was analyzed. Experimental Continuous Polymerflooding. Experimental Equipment and Materials. The experimental device is composed of a driving system, an experimental model, a pressure-measurement system, a produced-liquid-collection system, and a temperature-control system. According to the distribution of reservoir physical properties in the NN field, a parallel double-tube displacement experiment with a permeability ratio of 5 was designed. The experimental cores are artificial, with a tube length of 30 cm and an inner diameter of 2.54 cm. The low-permeability tube has 1624×10 -3 µm 2 permeability, and the high-permeability tube has 8488×10 -3 µm 2 permeability. The experimental temperature is 55°C, which is consistent with the formation temperature of the NN field. The polymer is partially hydrolyzed polyacrylamide. Experimental Procedure. The experimental process includes vacuum pumping, saturating formation water, obtaining core pore volume, saturating simulated oil, calculating oil saturation water drive to a specified water cut, continuously injecting polymer solution, and measuring data. The experimental injection rate is 0.2 mL/min, and the multiple of injected pore volumes (PV) is 0.6 PV. The NN field has weak edge water, and the water cut of the well group was 60 to 90% when polymerflooding was performed. Therefore, the design scheme mainly includes waterflooding and polymerflooding stages. The polymer- injection concentration was 3000 mg/L, and the injection mode is continuous, consistent with the field test.

Sustaining production from mature brownfields is becoming an uphill task in the current storm of pandemic plus economic crisis. In this year’s papers on mature fields and well revitalization, I have found operators focusing on making all-out efforts to improve their ongoing waterflood operations to extend the life of existing wells, which is preferred over drilling new infill wells. Waterflooding is the oldest method used for secondary recovery in oil fields because water is readily available and relatively inexpensive. Although the concept behind waterflooding is relatively simple and easy to implement, the reality is different, with many potential challenges such as water circulation because of poor reservoir conformance, induced matrix fracturing resulting in early water breakthrough, and reservoir souring, to mention just a few. The older the waterflood, the more susceptible it becomes to problems and challenges, and the most unavoidable challenge is managing increased amounts of produced water. A third of the papers studied this year focus on improved-/enhanced-oil-recovery techniques, and a majority of them focus on improving waterfloods through various techniques such as using classical analysis and data-driven technologies for redistributing injected water and integrating efforts with cross-disciplinary teams. Another area of focus is extending the life of existing wells. It is both a challenge and an opportunity. It is a challenge because operators must find a delicate balance between extending the life of an old well and jeopardizing the safety and integrity conditions in the field. It is an opportunity because it provides an attractive alternative for identifying and appraising possible behind-casing opportunities before plugging and abandonment. Several studies have been conducted to identify and appraise such opportunities.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 198586, “A New Continuous Waterflood Operations Optimization for a Mature Oil Field by Use of Analytical Work Flows That Improve Reservoir Characterization,” by Atul Yadav and Anton Malkov, SPE, Wintershall, and Essam Omara, Suez Oil Company, et al., prepared for the 2019 SPE Gas and Oil Technology Showcase and Conference, Dubai, 21–23 October. The paper has not been peer reviewed. In the complete paper, the authors present a novel approach that uses data-mining techniques on operations data of a complex mature oil field in the Gulf of Suez that is currently being waterflooded. Evidence is presented about how salinity data can be used to further justify the linkages between different wells obtained from cross-correlation analysis. The results presented in this research can be adapted to any waterflooded field to optimize recovery at frequent intervals where injection and production data are available continuously. Introduction Mature oil fields typically present challenges of increased water production and water handling. Considering the geological complexity and associated field-performance behavior, reservoir characterization to optimize water flooding is a major challenge. An integrated reservoir study was con ducted to minimize reservoir uncertainties and increase understanding of the field’s performance behavior. The acceptable history-matched model was used to estimate remaining oil potential, maintain and increase current production levels, and optimize the water-injection rate. Generally, history-matched models need to be updated throughout the life of producing fields as new subsurface data are acquired. Such integrated reservoir modeling studies, however, can be time-consuming and do not necessarily enable quicker decision-making around operational activities. The continuous recording of production and injection data presents new opportunities to apply novel analytical techniques to understand interwell connectivity in the reservoir. The current ability to store and analyze data, coupled with advances in the ability to interpret big data sets, has helped create an independent toolkit that provides analysis without the geological model. In addition, geological information such as pre-existing faults and the commingled or disconnected nature of production between different layers can be integrated to obtain and improve analyses from the analytical models. The authors analyze the results using Pearson’s cross-correlation analysis measure to obtain a qualitative analysis of the field. They also apply Spearman’s rank correlation analysis for the discussed field (henceforth named GOS for purposes of this paper) that helps compare injection and production data. The objective is to present a comparison between the analytical and the stream-lined approach to show consistency in reservoir characterization. The effective injector/producer pairs identified form an important component of the field development.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 196498, “First Natural Dumpflood in Malaysia: A Successful Breakthrough for Maximizing Oil Recovery in an Offshore Environment With Low-Cost Secondary Recovery,” by Muhammad Abdulhadi, SPE, Toan Van Tran, SPE, and Najmi Mansor, Dialog Group, et al., prepared for the 2019 SPE/IATMI Asia Pacific Oil and Gas Conference and Exhibition, Bali, Indonesia, 29–31 October. The paper has not been peer reviewed. The complete paper describes the first successful implementation of natural dumpflooding offshore Malaysia as a case study to provide insight into the value of using the approach to maximize oil recovery in a mature field, particularly in a low-margin business climate. Background Field B, located offshore Balingian province approximately 80 km northwest of Bintulu, has a water depth of 90 ft and is highly compartmentalized and faulted, with almost 100 faults present. The field features three subfields further divided into nine major fault compartments. Eight primary reservoirs exist, with more than 20 subreservoirs stacked atop one another with multiple drive mechanisms, including water drive, gas-cap drive, and solution gas drive. Several of these subreservoirs are thick sands between which communication exists through juxtapositions, shared gas caps, or aquifer. Other subreservoirs are isolated by thin layers of shale apparent in certain wells but absent in others. The high complexity of Field B requires any opportunity identified to be thoroughly evaluated and examined before execution. Field B is a moderately sized field discovered in 1976, with production commencing in 1984. During the 30 years of oil production, the field peaked at 30,000 B/D in 1990 and dipped to 3,000 B/D in late 1999. The facilities consist of four drilling platforms, a processing platform, and a compressor platform. A total of 48 wells were drilled in the field, with most wells completed as dual-string producers. The recovery factor (RF) of the reservoirs ranges from 10% for solution gas drive to 50% for strong water drive. The behaviors of these reservoirs are starkly different. The solution gas-drive reservoirs have poor-quality sand (less than 200 md), a low productivity index, limited sand thickness (less than 30 ft), limited sand connectivity, and sharp pressure decline after 2 to 3 years of production. The water-drive reservoirs, however, have good-quality sand (up to 5,000 md), a high productivity index, thick sand (greater than 40 ft), extensive sand connectivity, and limited pressure decline. The stark differences in the reservoirs’ behavior further complicate field management. The field currently is in late life, with recovery to date of 19% with an RF of 23%. Most of the water-drive reservoirs are already swept up to the crest, while the solution gas-drive reservoirs are depleted nearly to abandonment pressure. After 30 years of production, the total field water cut was at 80%, while oil production was approximately 5,000 B/D, signifying the diminishing economic life of the field.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30721, “Floating Offshore Windfarm Integrated Into Subsea Field Development: Case Study of the Saipem Windstream Concept,” by Benjamin Mauries, Giorgio Arcangeletti, SPE, and Christophe Colmard, Saipem, et al., prepared for the 2020 Offshore Technology Conference, originally scheduled to be held in Houston, 4-7 May. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. Operators are moving active production and injection equipment onto the seabed with the aim of reducing capital expenditures (CAPEX) or topside space requirements. Moreover, they want to minimize new production floating facilities. Given this scenario, overall electric power needs may become an issue because of the extra power demand caused by the increasing number of electric consumers placed subsea. The complete paper discusses a floating wind-turbine solution that is particularly cost-competitive for deepwater locations and that can unlock the possibility of deploying large wind-powered generators far from the coastline in deep water. Introduction Saipem launched an initiative aimed at finding a solution for management of subsea field power demand bearing in mind two primary considerations: Minimize CAPEX by reducing the distance between the subsea-field production location and the topside equipment supporting this production Decarbonize the field by adopting a renewable energy source Concept Background and Potential Application The operator has developed a floating substructure technology for offshore wind farms known as HexaFloat. This concept uses a minimal floating hexagonal tubular substructure supporting wind-turbine tower and providing necessary floatability. The substructure is connected by tendons to a basket counterweight filled with solid ballast providing stability with pendulum-restoring forces. The assembly of the basket and the substructure behaves as a rigid body if all tendons are loaded. This assembly provides flotation with excellent stability thanks to the distance between the center of gravity and the center of buoyancy. Because this stability is provided by weight, large hydrostatic stiffness is unnecessary. As a result, only the central cylinder is exposed to the wave energy. The whole floating system can be anchored with three to six low-tension mooring lines, depending on environmental conditions.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 198995, “Low-Salinity Water-Injection Optimization in the Namorado Field Using Compositional Simulation and Artificial Intelligence,” by Diana Mercado Sierra, SPE, Argenis Alvarez Rojas, and Victor Salazar Araque, Computer Modelling Group, prepared for the 2020 SPE Latin American and Caribbean Petroleum Engineering Conference, 27-31 July, Virtual. This paper has not been peer reviewed. The complete paper discusses optimization of a development plan involving low-salinity water injection (LSWI). This methodology combines compositional simulation and a mathematical optimization tool that uses artificial intelligence to maximize the net present value (NPV) of the project under evaluation. The adapted methodology allowed an optimal development plan, considering the uncertainty associated in the reservoir, by use of multiple geostatistical realizations and simultaneous history-matched models. LSWI LSWI is an enhanced-oil-recovery technique in which the salinity of the injected water is controlled with the objective of increasing the recovery factor. Of the mechanisms proposed for LSWI, wettability alteration is the most widely accepted for describing the increase of the recovery factor. The wettability change in reservoirs with the presence of sand-stones mainly is attributed to the multionic exchange between the injected fluid and the clay surface, as is the double layer expansion. From a technical point of view, the LSWI success is related strongly to reservoir lithology. An integrated analysis and optimization study was performed using numerical simulation to evaluate LSWI as an alternative for increasing the recovery factor in the Namorado field in the Campos Basin of Brazil.

This article focuses on the completion design of a multiple-zone water-injection project (MZWIP) that was initiated in 2016 in the Azeri-Chirag-Gunashli (ACG) fields in the Azerbaijan sector of the Caspian Sea. The MZWIP has ultimately proved a unique method of using intelligent completion interval-control valves (ICVs) in place of traditional sand-control completions. Four years after MZWIP implementation, nine wells with a total of 25 zones are injecting at required rates with zonal-rate live reporting across all five ACG platforms. To achieve the multizone injection facility, the requirement for a standard ACG sand-control injector design was discounted and a non-standard sand-management control technique developed using a cased and perforated (C&P) and downhole flow-control system (DHFC). During this program, BP ACG has successfully installed the world’s first 10,000-psi four-zone inline variable-choke DHFC wells with full surveillance across each zone including pressure, temperature gauges, and fiber-optic distributed temperature sensors (DTS). The development of this MZWI solution has significantly changed the ACG development plan and has been quickly expanded across all five ACG platforms. Accessing up to four zones in the same wellbore, this C&P DHFC well design is accelerating major oil volumes and will significantly reduce future development costs, maximizing wellbore utility in a slot-constrained platform. This could not be achieved by drilling more single-zone C&P injectors as it would erode business value through platform slot use, additional well costs, and slowing down field development. Multizone injection, therefore, became a necessity.

As I write this, I am in Week 4 of working at home because of COVID-19. Like many sectors of the economy, the oil and gas industry is affected by the practical issues raised by social isolation but uniquely so by the dramatic fall in oil price triggered by a reduction in demand and the battle for market share between major producing countries. All this is set against the backdrop of the energy transition and the long-term effect this will bring for our industry’s energy products. In difficult times, there is naturally a focus on maximizing the operational efficiency of existing assets, including enhanced-oil-recovery (EOR) operations and looking for capital-efficient ways to increase the resource base in existing assets. In the longer term, the outlook for EOR, at first sight, might seem to be particularly challenged in the face of the energy transition. This is because of both the effect of an increased focus on the life cycle - or well-to-wheels - carbon intensity of each barrel produced and the expectation of the existence of stranded, unproducible hydrocarbon resources if we are to stay within a global carbon budget and prevent unmanageable temperature rises. While some EOR technologies, particularly thermal, have unfavorable greenhouse-gas intensity metrics, others create the possibility of lower-intensity barrels. The increasing success in large-scale polymer flooding shows that EOR methods can recover more oil at reduced carbon intensity - more barrels with reduced water injection and produced-fluid handling. In the right circumstances, CO 2 EOR can enable CO 2 capture through the additional revenues it produces compared with pure storage or by producing barrels with a significantly lower carbon intensity that may qualify under low-carbon-fuel standards. Gas EOR, where it is managing associated gas to minimize flaring and venting of methane and CO 2 , also reduces the intensity of conventional waterflood and depletion barrels. There is an apocryphal curse that says, “May you live in interesting times.” Like it or not, we live in interesting times, times of unprecedented change, challenge, and uncertainty; however, times such as these drive creativity. In the energy transition, there is the opportunity to innovate in EOR technology, deployment, and operations to deliver cost-effective and lower-intensity barrels.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 199290, “Advanced Intervention Work Flow Brings High-Pressure Jetting to New Heights of Effectiveness and Enables Unprecedented Injection Coverage in Tight Carbonate Reservoirs,” by Samy Mohamed Abdelrehim, Daniel Gutierrez, and Sameer Punnapala, SPE, ADNOC, et al., prepared for the 2020 SPE International Conference and Exhibition on Formation Damage Control, Lafayette, Louisiana, 19-21 February. The paper has not been peer reviewed. The complete paper discusses an advanced matrix-stimulation work flow that brings reliability and flexibility to the acidizing of tight carbonate water injectors and has delivered injectivity improvements tight carbonate onshore reservoirs in the Middle East. The work flow leverages real-time downhole measurements and the presence of fiber optics in coiled tubing (CT) for telemetry, and relies on a high-pressure jetting tool, controlled with the help of real-time downhole pressure data, to enhance penetration of acid into the targeted intervals. Introduction Effective and long-term matrix stimulation of water-injector wells completed across tight carbonate reservoirs presents a significant challenge in the Middle East. Local practices for matrix stimulation of openhole horizontal carbonate water injectors consist of spotting hydrochloric acid treatment by CT along the uncased well section, using a specific fluid dosage per unit length of the pay zone. Thus far, that approach has delivered inconsistent results in wells completed across tight carbonate rock, most often leading to a rapid decline in injection rates following the treatment. An alternative work flow leverages distributed temperature sensing (DTS) to evaluate the original water-injection coverage across the reservoir. Each section benefits from a customized treatment that increases injectivity and improves uniformity of injection. A high-pressure jetting tool, controlled with the help of real-time downhole pressure data, is key to this work flow because it enhances penetration of acid into the targeted intervals. The engineered work flow has delivered injectivity improvements of nearly 8,000 B/D in the intervened wells, with the DTS survey confirming significant gains in injection coverage along the openhole section. The complete paper is organized into three sections - matrix stimulation challenges, proposed solution, and case studies. Matrix-Stimulation Challenges Unsuccessful acidizing treatments in carbonate formations usually have a common denominator: poor zonal coverage of the pumped stimulation chemicals. In water-injector wells, efficient reservoir sweep relies on understanding the optimal distribution of the stimulation fluid to maximize the water-injection capacity of the well. Understanding heterogeneity is fundamental for successful water injection in a carbonate reservoir. The presence of a dominant zone, also called the thief zone, is one of the most-obvious manifestations of heterogeneity, usually pointing to a layer with higher permeability than the average reservoir permeability. This heterogeneity leads to nonuniform injection profiles. Consequently, reservoir sweep by water becomes inefficient, leaving significant residual oil behind, risking creation of unwanted pressure differentials in the reservoir and leading to early water breakthrough in nearby producer wells . Fig. 1 shows the downhole intake profile for one water injector well from Field B. A nonuniform distribution of injection water across the uncased horizontal section is featured clearly, with almost all injected fluid going through the middle section [10,886 to 11,480 ft measured depth (MD)], leaving almost 75% of the open hole bypassed. The matrix-stimulation approach should be rethought to address the presence of thief zones.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 193238, “Investigation of Smart Waterflooding in Sandstone Reservoirs: Experimental and Simulation Study, Part 2,” by Hasan N. Al-Saedi, SPE, Missouri University of Science and Technology and Missan Oil Company; Ralph E. Flori, SPE, Missouri University of Science and Technology; and Alsaba Mortadha, Australian College of Kuwait, prepared for the 2018 Abu Dhabi International Petroleum Exhibition and Conference, 12–15 November, Abu Dhabi. The paper has not been peer reviewed. In this paper, the authors consider the effect of water chemistry on water/rock interactions during seawater and smart waterflooding of reservoir sandstone cores containing heavy oil. Oil recovery, surface-reactivity tests, and multicomponent reactive-transport simulation were conducted to understand smart waterflooding better. The authors determine that lowering magnesium-ion (Mg 2+ ) concentration results in lower additional oil recovery, and that lowering calcium-ion (Ca 2+ ) concentration leads to higher additional oil recovery. Introduction “Smart water” (SW) can be defined as a water engineered by manipulating the ionic composition (adding or removing ions) regardless of the resulting salinity. An upward pH shift has been reported in the literature during low-salinity (LS) and/or smart waterflooding. That upward shift modifies the wettability of sandstone, thereby increasing oil recovery. When high salinity is displaced by LS water, Ca 2+ will be desorbed from the clay surface because ion exchange occurs between hydrogen (H + ) and Ca 2+ at the negative sites of the clay surface. The organic materials will be then desorbed from the clay because of the reaction between the protonated basic and the acidic materials with hydroxide. The authors’ investigations on free-clay sandstone provided a different insight into such reactions. The observations from chromatographic columns of quartz showed an increase in the acetate detachment from the quartz surface with a significant pH jump during LS waterflooding. The oil-recovery observations from the quartz column supported the proposed mechanism. Previous systematic laboratory works indicated that the abundance of Mg 2+ in the formation water (FW) is more effective than Ca 2+ for a higher LS enhanced-oil-recovery (EOR) effect. Conversely, the abundance of Ca 2+ in the injected LS water has a larger effect on LS EOR. When Mg 2+ was present in the LS water, no oil-recovery improvement occurred. Methodology Brines. Synthetic FW and SW were prepared by dissolving sodium chloride (NaCl), calcium chloride (CaCl 2 ), and magnesium chloride (MgCl 2 ) in deionized water. Crude Oil. A reservoir crude oil was de-livered from eastern Kansas from the Bartlesville sandstone reservoir. The crude oil had a viscosity of approximately 600 cp at ambient temperature. The density is 0.83 gm/cc at 20°C. Reservoir Rock Description and Core Preparation. Five Bartlesville sandstone reservoir cores were drilled from the original 3-in. diameter to a 1-in. diameter preserved core from eastern Kansas. The preserved reservoir sandstone cores were delivered with 3-in. diameter. The most abundant mineral was quartz, followed by clays.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 19333, “Integrated Detection of Water Production in a Highly Heterogeneous and Tight Formation Using a CRM Model: A Case Study on Waterflooding Gaither Draw Unit, Wyoming, USA,” by Kailei Liu, China University of Geosciences; Xingru Wu, SPE, University of Oklahoma; and Kegang Ling, University of North Dakota, prepared for the 2019 International Petroleum Technology Conference, Beijing, 26–28 March. The paper has not been peer reviewed. Copyright 2019 International Petroleum Technology Conference. Reproduced by permission. The Gaither Draw unit is a heterogeneous tight formation with an average permeability of less than 0.1 md. After substantial water injection, there was no clear benefit of injected water for any producer. However, knowing the distribution of the injected water is critical for future well planning and quantification of injection efficiency. The objective of this study is to show how the capacitance-resistance model (CRM) was used on this field and how it validated the use of other independent methods. This paper demonstrates that integration of different sources of data in reservoir management is critical. Introduction Unlike numerical reservoir simulation, the CRM requires only the injection rates of each injector and the production rates of each producer as input to evaluate reservoir performance. The connectivity and the time constant that are estimated by fitting production rates can provide useful information about geological features and reservoir heterogeneity. With a clear understanding of reservoir heterogeneity, flow barriers and high-permeability zones can be identified. Significant reservoir heterogeneity may lead to poor sweep efficiency. These characteristic features make the CRM (the development of which is outlined in the complete paper) a unique and practical tool to investigate water-flooding projects. Basics of the CRM The root of the CRM is the governing material-balance equation stating that the mass difference in an arbitrary control volume (CV) is equal to the mass difference between injected and produced fluid passing through this CV. Then, the governing material-balance equation is combined with a linear productivity model to obtain an ordinary differential equation. The semianalytical solution of the ordinary differential equation forms the CRM. In the field case, there are often many injectors and producers, which would be a large nonlinear optimization problem in the CRM. A CRM-producer (CRMP) model can be used to reduce the number of time constants and increase computational speed. The equations contributing to such a model are provided in the complete paper. Case Study The study area is located in the Parkman reservoir, which is a part of the Powder River Basin in southeast Montana and northeast Wyoming. The Parkman Sandstone Member of the Upper Creta-ceous Mesaverde formation is the oldest sandstone member in a widespread cycle of late Cretaceous regression. The Parkman reservoir consists of multiple stacked sands 5,000 to 9,500 ft deep. There are three dominant lithologies of the Parkman reservoir. The first is pro-delta shale and siltstone, which includes very fine and well-sorted sandstone. The second is medium-grained sandstone, which lies as coarsening-upward successions mixed with siltstone. The last is silt and mudstone, which gradually changes from exhibiting carbonaceous to lignitic characteristics.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper OTC 29552, “Subsea Water Treatment Pilot Testing at the Ekofisk Field in the North Sea,” by Eirik Dirdal, National Oilwell Varco, prepared for the 2019 Offshore Technology Conference, 6–9 May, Houston. The paper has not been peer reviewed. Copyright 2019 Offshore Technology Conference. Reproduced by permission. A subsea water-treatment system designed to leverage space availability, steady temperatures, lower bacteria levels, and other natural benefits of the seabed environment was successfully installed during pilot testing at the Ekofisk field offshore Norway. After several phases of testing, a full-scale water-treatment module was built and installed, and at the time the complete paper was written, the pilot had moved into the long-term testing phase to determine the system’s viability under North Sea field conditions. According to the author, if the system succeeds, it could drive a major change in injection-water management offshore. Introduction The Ekofisk field was originally developed with pressure depletion as the primary drive mechanism. After several decades of production, significant resources are still in place. Limited gas injection and comprehensive water injection have contributed to a substantial increase in oil recovery. Large-scale water injection began in 1987, and has been extended in several phases. Water displacement of the oil has been successful, and the recoverable resources have been adjusted correspondingly upward from the original 17% to an estimated final recovery factor of greater than 50%. An important factor in the success of a waterflood project is the quality of the injected water. In worst-case scenarios, poor water quality can cause plugging and reservoir souring. Water quality is greatly affected by contaminants such as suspended solids, corrosion products, scale, and bacteria. Controlling corrosion and disinfection of biomass are two major challenges associated with waterflood. The two challenges are linked because oxidants are required to reduce bacterial activities that could lead to microbial-induced corrosion, but the oxidants also promote corrosion. Joint-Industry Project (JIP) Results Development of the injection-water treatment system described in the paper began in 2004. Det Norske Veritas’ recommended practice for qualification of new technology has been used throughout the development process. On the basis of successful experimental testing that demonstrated proof of the concept, a JIP supported by several oil and gas majors was launched in 2009. A prototype was built and tested in 65 m of water depth in Oslofjorden, a sheltered environment in a fjord, to verify the water-treatment module’s performance and reliability through seasonal variations in real offshore conditions. Results demonstrated that the treatment method, which combined various electrolysis approaches, provided very good water quality, in many aspects superior to that achieved by topside seawater-treatment plants.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 191951, “A Smart Software System for Flow-Assurance Management,” by Akanksha Jain, SPE, Nilay Patel, SPE, Paul Hammonds, and Shirish Pandey, Cairn Oil and Gas, prepared for the 2018 SPE Asia Pacific Oil and Gas Conference and Exhibition, Brisbane, Australia, 23–25 October. The paper has not been peer reviewed. Access to real-time production and injection data is of great benefit to the production optimization engineer. This paper describes a smart management system used for retrieving and evaluating all flow-assurance-related data for more than 700 of the operator’s onshore and offshore wells. The paper discusses system architecture, interface details, design, functionality, visualization, application, and benefits. Introduction Cairn Oil and Gas is the operator of three major blocks currently producing in India: Block RJ-ON-90/1 (Rajas-than), CB/OS-2 (Cambay Basin), and PKGM-1 (Ravva) constituting more than 700 wells, operated on behalf of its joint venture partners. These wells are either self-flowing or use a variety of•• artificial-lift systems. Waterflooding provides pressure maintenance in most fields. Injectivity of water injectors is, therefore, critical in maintaining levels of water injection required to achieve the stipulated recovery factor. Formation fluids have physical and chemical properties that have posed several flow-assurance challenges over time with regard to outflow performance and processing in surface facilities. These flow-assurance issues include inorganic scaling, organic scaling, corrosion, sand production, injectivity decline, and injector conformance, all of which can affect productivity and injectivity of the fields and thus lead to relatively inefficient waterflood. The Challenge Various software products are currently in use for management of operations requiring production- and injection-enhancement treatments in different fields. To ensure that wells are operating optimally, an integrated approach combining robust monitoring and data analysis of parameters affecting well performance is ideal. This was previously achieved through the cumbersome process of data retrieval from different sources, which was then compiled in different Excel spreadsheets. This time-consuming process delayed analysis and permitted errors in data input. As the importance of improving the quality of data management and analysis became clear, the need arose for automation of flow-assurance management across all assets. The platform described in this paper was intended to help design, evaluate, and monitor all chemical-intervention jobs, and monitor corrosion levels and scale-inhibitor squeeze performance by incorporating data from various sources within the production system. The analysis of the data enabled by this fully automated Web-based software helps in the execution of cost-effective treatments and well-production optimization. The same software system is also being used for well-integrity management for•all assets.

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.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 192840, “Field-Trial Results for New Sand-Control Technology for Water Injectors,” by Steven Fipke, SPE, Tendeka; J.E. Charles, SPE, Shell; and Annabel Green, Tendeka, prepared for the 2018 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 12–15 November. The paper has not been peer reviewed. In 2014, a research and development (R&D) project was initiated to increase the life expectancy of Gulf of Mexico (GOM) Miocene and Lower Tertiary water-injection (WI) wells, several of which had suffered a severe loss of injectivity within only a few years of completion. The solution was to find a way to prevent fine material from entering the completion while sustaining high injection rates, with no loss of injection pressure or requirement for additional horsepower. A new flow-control device (FCD) and completion system were developed along with intrinsic nonreturn valves (NRVs) that prevent any backflow or crossflow during•shut-ins. Developing the Flow-Control Technology Tubing-deployed injection valves and regulators have been available for many years. However, these cannot address the problem of annular flow. The most-damaging factor in solids production is likely crossflow, wherein differently pressured injection zones can flow between layers inside the tubing or casing annulus. Crossflow can be eliminated only by blocking the flow at the sandface. This solution also would mitigate the damaging effects of water hammer by blocking pressure waves from entering the lower completion. Check-valve components must fit within sand-control screens or be deployed across multiple zones of the injection tubing.• During the R&D phase of the project, researchers used extensive laboratory testing, flow-loop testing, and computational-fluid-dynamics modeling to develop a series of NRV prototypes. The technology was designed to handle a variety of well conditions, including erosion, plugging, temperature, and repeated checking cycles. All FCD components, including the NRV technology, are manufactured with high-alloy stainless steel and tungsten-carbide components to resist tortuous downhole conditions for up to 15 years. FCD prototypes and design iterations were tested over 18 months and a final design was qualified to withstand repetitive pressure- checking cycles reliably at 1,500 psi (and up to 10,000-psi static differential•pressure).• The laboratory testing conducted to finalize the project development stage is described in detail in the complete paper; it consisted of leak-rate, erosion, plugging, and screen-construction stages. One determination of this testing was that the placement of the screen over the FCD joint could cause erosive wear because of the placement of the screen ribs over the valves. An alternative rib wire was designed that could place the FCD between wires without compromising the strength of the screen. With laboratory and workshop testing completed by early 2017, the focus of the project shifted to identifying and organizing a field trial for the new technology in a low-cost, low-risk environment.

Technology Focus According to the US Energy Information Administration, West Texas Intermediate (WTI) annual average oil prices have fluctuated between $93.2 and $43.3/bbl between 2014 and 2019. The price was $76.4/bbl (WTI spot price) at the beginning of October 2018, dropping approximately 41% to $45.4/bbl on 1 January 2019, reached a peak of $66.3/bbl on 23• April 2019, and then depressed to today’s (15 August 2019) $55.1/bbl. The lower and unstable oil prices since 2015 have continuously pushed operators and service companies to reduce costs and improve capital efficiency in all aspects of business, including sand management. This is reflective of the industry’s attention on fundamental and proven sand-control practices. This year, many published works have focused on standalone screens as the most cost-effective solution when compared with other more-expensive approaches such as gravel packing or frac packing. Screens are reliable for sand control when properly designed and used in suitable sand-prone environments. The latest technologies in this area have featured developments focusing on mitigating plugging and erosional damage. While sand control in production wells catches much attention, water-injection wells also are subject to sand-control problems triggered by water hammer, crossflow, and backflow. Newly developed screens for water-injection wells have been demonstrated with promising results in the latest field trials in preventing formation sand from flowing back and, therefore, maximizing injectivity. In this issue, I have selected a variety of papers with more emphasis on cost-effective sand-management practices and operations. Please read the following three paper synopses with the recommended additional readings for more information, and do not forget to attend the upcoming SPE Annual Technical Conference and Exhibition scheduled for 30 September through 2 October in Calgary. Recommended additional reading at OnePetro: www.onepetro.org. SPE 192090 Sand Prediction for a Cost-Effective Marginal Greenfield Development by Siti Aishah Mohd Hatta, Petronas, et al. SPE 193697 Risk Assessment in Sand-Control Selection: Introducing a Traffic Light System in Standalone-Screen Selection by Mahdi Mahmoudi, RGL Reservoir Management, et al. SPE 193698 Successful Installation of Standalone Screen in Challenging Environment in Umm Niqa Field by Amr Zeidan, Kuwait Oil Company, et al.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 190456, “Increasing Well Injectivity and Productivity by Seismic and Seismochemical Stimulation,” by K. Furman, S. Miftakhov, SPE, M. Nazyrov, R. Nefedov, and V. Zamakhaev, Terratec, and A. Andrianov, AIA Consulting, prepared for the 2018 SPE EOR Conference at Oil and Gas West Asia, Muscat, Oman, 26–28 March. The paper has not been peer reviewed. Many oil fields in Russia and the Commonwealth of Independent States are in late-development stages, with waterflooding having being used for decades. A relatively new technology in production optimization is wave stimulation, in which the wellbore and reservoir are treated by acoustic, seismic, or other types of waves generated by tools. Approximately 250 wells have been treated in this manner, with a high success rate and significant oil-production increase. This paper discusses the potential of seismic and seismochemical well simulation in particular within the scope of this recent technology. Introduction Wave-stimulation technologies have short treatment times and can be applied in different types of formations and wells. This paper focuses on seismic-impact well treatment. The well treatment is based on a wellhead pneumatic generator that uses special valves. Energy is generated at the surface with compressed inert gas and released into the well. A shock wave then propagates through the liquid-filled well column and transforms into a seismic wave in situ. Movement of the shock wave creates a damped self-oscillating process with a frequency of 0.2 Hz, the effect of which can stimulate injection and production wells. One method of increasing the efficiency of seismic stimulation is use in conjunction with the injection of chemical reagents. Mechanisms of Seismic and Seismochemical Stimulation No generally accepted theory describes the effects of seismic impact on reservoirs. On the basis of theoretical, experimental, and field research, various authors have proposed mechanisms and concepts, which are described in the complete paper. Porosity and Permeability Change in Dilatancy Area for Sandstones. Studies of dilatancy processes under dynamic effects have shown that, for sufficiently high unevenness of the stressed state, dilatancy processes occur even at stresses that are only 3–5% of the ultimate strength, causing irreversible change in the rock density, porosity, strength, and permeability. Dilatancy is observed in the deformation of soils and rocks. Extensive experimental data on the deformation of a wide class of formations under volumetric stressed-state conditions show that compaction is seen in highly porous rocks, while loosening is seen in dense rocks. Reduction in the volume of highly porous rocks occurs as the result of a reduction in the number of defects. Positive (compaction) and negative (loosening) rock-dilatancy values are related to the value of the initial effective porosity. If the effective porosity value is less than a certain limiting value, then the rock is dense and loosens during deformation. When the effective porosity is greater than its limiting value, the rock is compacted. However, the compaction of the rock can occur up to a certain value, after which it breaks down. The main influence on the amount of dilatancy is the result of an uneven load (i.e., the ratio of the minimum main stress to the maximum). However, at the same level and at the magnitude of the uneven loading in the stronger rocks, the dilatant component of the volume deformation exceeds the rock compaction more than is seen in less-rigid rocks.

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.