International Petroleum Technology Conference Research Articles

Locally Produced Sustainable and Resilient Surfactants for Enhanced Oil Recovery

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 24518, “Locally Produced Sustainable and Resilient Surfactants for Enhanced Oil Recovery,” by Syed Muhammad Shakil Hussain, SPE, Muhammad Shahzad Kamal, SPE, and Afeez Gbadamosi, King Fahd University of Petroleum and Minerals, et al. The paper has not been peer reviewed. Copyright 2024 International Petroleum Technology Conference. _ Chemical flooding is a major enhanced oil recovery (EOR) method for recovering residual oil within rock pores. Injected chemicals such as surfactant, however, must be soluble in low- and high-salinity brine, compatible with reservoir ions, and stable at elevated temperatures. The main objective of the study described in the complete paper is to explore the potential of locally produced surfactants for EOR in high-temperature and high-salinity reservoir environments. Design and synthesis of the new surfactants were achieved using green or no solvents. Importance of Chemical EOR Because only 15–20% of hydrocarbons can be extracted in the primary recovery stage, the waterflooding or gas-injection techniques usually are applied in the secondary recovery stage to extract 15–20% more oil and maintain the oilfield’s original pressure. After the application of these two techniques, however, a large amount of oil remains, the extraction of which requires the use of EOR, which can include thermal, gas, or chemical techniques. In thermal EOR, hot water or steamflooding are usually used to recover heavy oil. Currently, other thermal EOR methods such as in-situ combustion or steam-assisted gravity drainage receive considerable attention, especially in reservoirs containing heavy to extra-heavy crude oil. Gas methods normally are used in reservoirs featuring light and volatile oil. CO2 flooding is perhaps the most extensively applied gas EOR method for light oil extraction. Other gases such as nitrogen, hydrocarbon gas, acid gas, and air also are used for oil recovery. Chemical EOR involves the injection of chemicals including surfactants, polymers, alkali, and mixtures thereof. The polymer tends to increase the viscosity of the aqueous phase and lower the permeability of reservoir rocks. Surfactants minimize the interfacial tension (IFT), cause emulsification, and alter the wettability of the reservoir rocks. Alkali flooding generates in-situ surfactant by reacting with organic acid and ultimately reducing the IFT. Surfactants are organic compounds having both lipophilic and lipophobic parts. The lipophilic part is called a nonpolar compound and is soluble in the oil phase. The lipophobic part is termed a polar group and is soluble in the aqueous phase. Because of the availability of both lipophilic and lipophobic compounds in the same chemical structure, the surfactant stays on the interface ­of the water and oil phase and reduces the IFT. Based on the charge of the lipophobic head, the surfactants can be classified as nonionic, cationic, anionic, and zwitterionic (Fig. 1). Each class of surfactants possesses unique properties. For example, anionic surfactants are the material of choice in sandstone reservoirs because of their low adsorption into reservoir rocks. Similarly, the cationic surfactants exhibit minimum adsorption in carbonate rocks because of charge repulsion. Zwitterionic surfactants (ZS) show high heat-stability and salt-tolerance properties, and nonionic surfactants are known for their use as cosurfactants or solvents.

Remedial Conformable Sand-Control Technology Deployed Offshore Colombia

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 23690, “First Horizontal Deployment of Remedial Conformable Sand-Control Technology in Colombia: Qualification and Case Study,” by Suzanne Stewart, SPE, TAQA, and Jose M. Bermudez, SPE, and Camilo Mazo, Hocol, et al. The paper has not been peer reviewed. Copyright 2024 International Petroleum Technology Conference. _ The challenge of remedial sand control lies in the fact that the system must pass through restrictions in the upper completion before ideally conforming to the inner diameter (ID) of the zone requiring sand control. The complete paper describes the qualification of a multilayer, open-cell matrix polymer (OCMP) system for the first horizontal deployment in an offshore gas well. The system is capable of being deployed remedially through tight tubing restrictions while providing conformant sand control in a horizontal wellbore without the need for gravel packing, making the approach particularly valuable for scenarios where surface space is limited. Background During 2006, gas Wells CH-20, CH-19, and CH-18 were originally drilled and completed in the B2 zone in the Chuchupa field offshore Colombia. Wells CH-20, CH-19, and CH-18 experienced water breakthrough from the aquifer in late 2016, 2018, and 2020, respectively. The first workover operation in these wells was performed in 2021. The aim was to isolate the B2 zone with a packer and to perforate the slightly shallower B1 zone to access attic gas. In Well CH-18, an inflatable packer between Zones B2 and B1 was installed successfully, resulting in the ability to produce at full potential, while Wells CH-19 and CH-20 recovered their potential partially but below the calculated target rate. A new operation for the three wells was planned in 2022 to set a mechanical packer to isolate Zone B2 and reperforate Zone B1 to increase flow area, reduce drawdown at the sandface, and diminish the risk of sand production. However, because produced sand had accumulated in front of the perforations in all wells, removing the sand and setting the mechanical packer was impossible. At present, Wells CH-19 and CH-20 are not producing and Well CH-18 is on lower-than-calculated target production. Given the production difficulties, the plan is to isolate Zone B2 successfully in all wells, clean the wells, and install effective remedial sand control with significant surface-space constraints. OCMP: Conformant Remedial Through-Tubing Sand Control The OCMP system evaluated and subsequently selected for this application consists of multiple layers of highly porous (up to 85%) and permeable (40 darcies or greater) OCMP bonded to a specially designed base pipe. The compressibility of the system enables it to be run in hole compressed within a sleeve to allow passage through tight restrictions in the upper completion; then, once in place, the sleeve can be removed, allowing a return to the original shape and conformance to the ID of the sand-producing section. The system can be run on slickline, braided line, coiled tubing, or pipe. If deployed with a hydraulic conduit, it has the capability to perform sand cleanout during deployment and can incorporate an integral hydraulic-set, high-expansion anchor. If run with slickline or braided line, it is necessary to run an anchoring device on a separate trip; then, the first OCMP system can be anchored in place.

Fiber-Reinforced Thermoplastic Sucker Rods Provide Artificial Lift Efficiencies

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 23949, “Fiber-Reinforced Thermoplastic Sucker Rods Providing High-Strength, Lightweight, Low-Cost, and Environmentally Responsible Artificial Lift Efficiencies,” by Jeff Saponja, SPE, Oilify, and Corbin Coyes, SPE, and Michael Conner, SPE, Q2 Artificial Lift Services. The paper has not been peer reviewed. Copyright 2024 International Petroleum Technology Conference. _ The complete paper focuses on the development of fiber-reinforced thermoplastic (FRTP) sucker rods, highlighting their potential advantages and challenges, for rod pumping (in general) and for offering an earlier transition from electrical submersible pump (ESP) pumping or gas lifting to reliable deep high-rate rod pumping. A unique feature of an FRTP composite rod is its remarkably high shear failure resistance compared with that of a thermoset composite rod. A high shear-failure resistance means the rods have compressional loading tolerance and that an entire sucker rod string could be comprised of FRTP sucker rods. Introduction Sucker rods made from steel are relatively heavy. Extensive well-specific designs require tapering of rod strings to optimize the overall sucker rod string weight relative to the strength and fatigue requirements and consideration of the dynamic loadings from accelerations and decelerations of the rods and fluids, frictional effects, and structural or power limitations of the pump jack or unit at surface. Steels suffer from corrosion risks. Corrosion, which rapidly can accelerate fatigue failure, often is the root cause of sucker rod failure. Fiber-reinforced composites (i.e., fibers surrounded by or wetted by a resin matrix) have gained considerable popularity because they can be tailored to have outstanding mechanical, thermal, and physical properties, and have superior material mechanical properties to metal. The fatigue behavior of composite materials and structures is complex because composites fail by a series of, or collection of, damage mechanisms, including fiber breakage, matrix cracking, fiber/matrix debonding, delamination, and the effect of shear-induced damage on cracks. Cracking can be slowed somewhat if the reinforced fibers are of high stiffness. Composite materials can offer a lower environmental footprint over their entire life cycle. They can require less energy to manufacture, thereby reducing CO2 emissions. A high strength/weight ratio offers less energy consumption during operational use, further reducing CO2 emissions. Composite materials can be recycled and reused. Composite sucker rods, in the form of thermoset fiberglass sucker rods, have offered a high strength/weight ratio with greater corrosion tolerance, but they are too stretchy from a low glass fiber tensile modulus of elasticity for deep high-rate rod pumping and when a high production-rate decline is likely. This limitation results in a large bottomhole pump-stroke variability as operating conditions change. Such rods have low tolerance to compressional and impact loads, forcing a larger proportion of a sucker string to remain as steel. They are also more costly than steel rods. For sucker rod pumping, an ideal composite rod should tolerate compressional loads and feature high impact resistance and high fatigue endurance with an ability to limit or control crack formation. A composite material that potentially offers these important sucker rod properties is FRTP.

Solution Enables Well Surveillance in Stacked Reservoirs With Near-Critical Fluids

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 23912, “Digital Solution for Well Surveillance in Stacked Reservoirs With Near-Critical Fluid Systems,” by Kristian Mogensen, SPE, Carlos Mata, SPE, and Swarjit Samajpati, ADNOC, et al. The paper has not been peer reviewed. Copyright 2024 International Petroleum Technology Conference. _ Fully compositional integrated asset models (FC-IAMs) are being deployed for an increasing number of fields in the operator’s portfolio. The complete paper describes the development of comprehensive digital well surveillance and field-production optimization for an offshore field consisting of four stacked reservoirs, each containing near-critical fluids. Augmenting the FC-IAM with high-frequency sensor data in addition to proprietary tools to actively monitor well performance helps identify and pursue opportunities to maximize oil production from the field, subject to several system constraints. Introduction The field is approximately 120 km offshore Abu Dhabi. During the appraisal phase, eight wells penetrated the structure and confirmed that the predominant lithologies are composed of dolomite and anhydrite, with subordinate limestone. Production of oil and gas comes from four main reservoirs—A, B, C, and D. The ongoing development centers around miscible gas injection along the crestal part of each reservoir and peripheral water injection. Integrated asset models are one of many key initiatives supporting the operator’s Smart Production Growth initiative. Although the calculations identifying scope for improved production rates are firmly founded in science, substantial digitization efforts are required to automate, streamline, and sustain any such digital solution. Fig. 1 illustrates the fact that company database management plays a fundamental role in providing reliable input to keep models updated and fit for purpose. Fluid-Property Modeling Each of the four producing reservoirs contains near-critical fluids exhibiting a steep compositional depth gradient, which means that the solution gas/oil ratio (GOR) is well-specific and may change over time. The GOR trend is governed by several factors. The lightest part of the fluid column may be produced first because of the improved mobility; this would lead to a decreasing solution GOR over time. However, because of the crestal miscible gas injection, significant swelling will result in a gradual GOR increase followed by gas breakthrough. Solution GOR increases because of gas swelling. It is important to make the distinction between solution gas and free gas because the operational guidelines dictate that the reservoir pressure should be maintained above the saturation pressure and above the minimum miscibility pressure. Well-Test Validation Workflow The compositional framework adds an extra layer of complexity because fluid composition needs to be specified at the well level. A robust procedure is needed to first assign an initial reservoir fluid composition to each well. The second key task is to capture changes over time. The method of solution is referred to as a target GOR calculation. For any given fluid system, an equation of state (EOS) model must be tuned to experimental data to convert compositional information to black-oil properties at specific pressures and temperatures. A so-called anchoring fluid composition initially is assigned to the well, and the EOS can then calculate the resulting GOR and other variables from a simulated separator test. The evolved gas and liquid phases are then recombined mathematically to match a measured GOR from a production test. Matching is an iterative process but normally converges very quickly.

Physics-Informed Machine Learning Applied to Complex Compositional Model in a Giant Field

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 23730,“Physics-Informed Machine-Learning Application to Complex Compositional Model in a Giant Field,” by Guido Bascialla, SPE, ADNOC, and Coriolan Rat and Soham Sheth, SLB, et al. The paper has not been peer reviewed. Copyright 2024 International Petroleum Technology Conference. _ Compositional reservoir simulation is a time-intensive activity demanding complex physics. In the complete paper, the authors review the advantages of machine learning (ML) in complex compositional reservoir simulations to determine fluid properties such as critical temperature and saturation pressure. An ML approach to predict critical temperatures during simulation based on the Heidemann-Khalil method is implemented, resulting in more-accurate results with lower computational cost, outperforming the standard method and improving performance on a giant field model with compositional gradient and miscible gas injection. Field Description The case study refers to a giant offshore carbonate field composed of multiple reservoirs. Production is currently in a rampup phase; crestal miscible hydrocarbon gas injection was implemented soon after startup. The availability of high-potential gas producers as a source of makeup gas and the placement of peripheral water injectors maintains the reservoir pressure above minimum miscibility pressure. All reservoirs show complex variable slope compositional gradients along thick oil columns of hundreds of feet (Fig. 1). To match the fluid behavior and the variation of fluid properties with depth, the equation of state needs at least nine components. The rock quality mainly is controlled by diagenesis. Thirteen rock types were modeled. The permeability can change up to four log cycles for the same porosity. Most of the reservoirs are highly heterogeneous, with features such as high-permeability streaks and baffle zones. A wide range of capillary pressure curves is present; these mainly depend on permeability and lithology. Most development wells were completed with inflow control devices (ICDs) to control gas and water breakthroughs and optimize oil production. The combination of numerous ICDs and long slanted production intervals (i.e., thousands of feet) make wellbore-reservoir coupling critical for proper history matching and forecasting. The model grid size in the horizontal direction is 328 ft, which is considered optimal according to simulated sensitivities. The vertical layering is very fine in order to capture the reservoir heterogeneity; the cell thickness ranges from 1 to 1.5 ft. This results in a model with 3.5 million active cells, which makes the simulation performance and run time very challenging when coupled with compositional gradient and ICDs. Phase Labeling In this section of the complete paper, the authors review why accurate phase labeling is important in compositional simulation and how it can lead to convergence problems, particularly for cases with gas injection. A traditional method is compared with an ML method on a simple model using a complex dummy fluid model to highlight issues that may arise in more-complex simulation models.

Partnerships Crucial in Developing Nonmetallic Downhole Tubulars

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 23491, “Role of Ecosystem Partners To Make Nonmetallic Downhole Tubulars a Reality,” by Ahmed Aladawy, SPE, and Ameen Malkawi, SPE, Baker Hughes, and Omar El Shamy, SPE, Novel Non-Metallic Solutions. The paper has not been peer reviewed. Copyright 2024 International Petroleum Technology Conference. _ Nonmetallic (NM) downhole tubulars offer a longer lifetime than their steel counterparts while eliminating corrosion concerns and lowering total cost of ownership. Making them a reality, however, requires a rigorous ecosystem with multidisciplinary skill sets and technology expertise. The complete paper discusses the challenges that face the development of such tubulars starting from academia and research institutes to complement expertise and computer computational power and moving through to material suppliers and manufacturing facilities for pipe prototyping. NM Pipe Construction and Technology Status NM pipes also can include metallic elements, where a hybrid system of NM layers is incorporated into multilayered pipe structures that assume specific roles, similar to a metallic pressure armor layer in subsea flexible risers, jumpers, and flowlines. Another example is polymer-lined steel rigid pipes with glass-fiber reinforced epoxy (GRE), or a dual-layer thermoplastic-lined reinforced pipe (Fig. 1). Composite-based NM pipes can broadly be categorized into reinforced thermoplastic pipe (RTP) and reinforced thermoset pipe (RTR), with glass-fiber reinforced plastic pipe (GRP) and GRE considered a subset of RTR. RTP consists of thermoplastic matrices and layers that can soften after heating and can harden when cooled in a reversible process, thus having the potential to recycle. Because of the flexibility of thermoplastic polymer, RTP pipes up to hundreds of meters long can be spooled on reels and deployed through rigless operation, with reduced system cost and deployment time. This synopsis will concentrate, as does the complete paper, on RTP. RTP pipe design can be classified as unbonded, semibonded, or fully bonded. Essentially, three layers of constituents for RTP exist: the inner layer is a fluid barrier (liner), the second layer is a load-bearing component (reinforcement), and the outer layer is external protection (cover). Unbonded RTP pipe means that the layers are not heat-fused to one another during manufacturing and are free to move between layers. This type of RTP pipe usually is low to medium in pressure rating, especially with regard to collapse rating, but also is lower in manufacturing cost and is suitable in onshore applications for fluid transportation. To increase the pressure rating, semibonded RTP pipes can be considered if pipe thickness is a limitation. For offshore and downhole applications, however, where higher pressure and temperature ratings are required, fully bonded RTP pipes, more commonly known as thermoplastic composite pipes, are preferred to handle high burst and collapse-pressure requirements and more-consistent load transfer across the structure. All RTP types can be manufactured continuously into pipe lengths of hundreds of meters because of their flexibility, but fully bonded RTP may be limited to larger-bend radii than unbonded or semibonded RTP; consequently, a need exists to consider reel-size limitations or even carousels to wind long pipe lengths during manufacturing. Conversely, fully bonded RTP structures may be easier to model and analyze than unbonded pipe.

Adaptive Approach for Reservoir Modeling Reduces Project Time, Improves Collaboration

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 23935, “Breaking the Chain: Novel Use of Adaptive Model Approach for Reservoir Modeling Reduces Time Duration of Project and Improves Collaboration,” by Anthony R. Thompson, SPE, and Cesar E. Zerpa Bolivar, SPE, Saudi Aramco. The paper has not been peer reviewed. Copyright 2024 International Petroleum Technology Conference. _ The complete paper details how the reservoir modeling workflow can be accelerated, and uncertainty reduced, even for challenging greenfield prospects by constructing multiple small fit-for-purpose integrated adaptive models instead of one all-encompassing model. This workflow reduces the number of items on the critical path while simultaneously enabling static and dynamic data to be integrated before the static model is finalized. In addition, this approach enables new ideas to be evaluated more rapidly without affecting the critical path of the project. Adaptive Models Adaptive models are constructed to evaluate a single parameter, although this does not preclude an adaptive model being used to answer more than one question simultaneously. Critical to the successful use of adaptive models is the fact that they can be constructed quickly. This enables the various inputs received to be assessed and quality-controlled within the static and dynamic models the moment the input or interpretation becomes available. The construction of adaptive models normally is best achieved through the construction of a workflow in the static modeling package. Initially, the workflow may only consist of the construction of a grid in which to start to place wells. As data become available and are quality-controlled into the model, in most cases, this can be included into the workflow, enabling more constraints to be applied to the subsequent modeling framework. When the adaptive model is being simulated dynamically, it is critical that the model runs quickly. The use of a sector model can be considered for greenfields because the history-matching parameters before production starts are limited to the vicinity of the well. Full-field models are only required when an event occurs across the whole of the reservoir. Adaptive Modular Modeling Process In contrast to the classical approach to reservoir modeling, which uses a chain-type approach, the use of adaptive models brings components together in the sequence of work completion. This means that the various components of the model can be competed when the resource or team member is available. Thus, until very near the end, the project is unlikely to be waiting on the input of one person.

Study Reviews Reservoir Engineering Aspects of Geologic Hydrogen Storage

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 23943, “Reservoir Engineering Aspects of Geologic Hydrogen Storage,” by Johannes F. Bauer, Mohd M. Amro, SPE, and Taofik Nassan, SPE, Technical University Bergakademie Freiberg, et al. The paper has not been peer reviewed. Copyright 2024 International Petroleum Technology Conference. Reproduced by permission. _ Safe and effective large-scale storage of hydrogen (H2) is one of the greatest challenges of the global energy transition and can be realized only through storage in geological formations. The aim of the study detailed in the complete paper is to address and discuss the reservoir engineering aspects of geological H2 storage (GHS). The study is based on two sources: first, a comprehensive literature review and, second, experimental and numerical work performed by the authors’ institute. H2 Pressure/Volume/Temperature (PVT)/Phase Behavior The definition of the PVT/phase behavior of reservoir fluids is crucial in GHS because thermodynamic properties significantly affect safety and effectiveness. The properties of H2 are widely known and modeled, but its reaction with other gases, such as in-situ gases like natural gas in depleted gas reservoirs (DGR), currently is under investigation. Although the ideal gas law can account for H2 behavior at low pressure, accurate depiction of its thermodynamic properties requires more-sophisticated equations of state (EOS), especially when it is mixed with other gases such as methane. Most commercial reservoir simulators use EOS packages that can model the complex properties of these mixtures, mostly within required reliability. In most instances, calibration is still required if experimental PVT data are available. Reservoir Engineering of GHS. GHS projects must meet three crucial technical benchmarks for underground storage: capacity (storage volume), injectivity/productivity (rate of injection/withdrawal in relation to wellhead pressure), and containment integrity (prevention of leakage). Economic sustainability requires that projects must adhere to these standards, which may vary according to the selected geological formations. Although various subsurface structures can store H2, only specific formations such as salt caverns (SCs), saline aquifers (SAs), and depleted gas/oil reservoirs (DGRs and DORs), fulfill the requirements. While the complete paper discusses all three of these formation types in detail, this synopsis will concentrate on SCs. GHS in SCs. SC storage typically involves up to three wells for one cavern with a volume of up to 500,000 std m3, providing a delivery rate of 8,500–17,000 std m3/day. Working gas accounts for up to 65% of the total gas, while water should be kept to a minimum. SCs usually allow between six and 12 operating cycles per year, each lasting approximately 10 days for withdrawal periods. SCs offer high H2 purity and sealed storage. The storage capacity of caverns in Germany is determined by their volume and pressure limitations while avoiding any negative geomechanical effects. These caverns can range in depth from 500 to 2000 m, with heights of up to 400 m. Approximately 30 to 50% of the total stored volume is used as cushion gas to maintain production pressure. Estimating the capacity of these caverns relies on their geometry and thermodynamics, resulting in relatively lower uncertainties when compared with storages in porous media.

Intelligent Completion Enables Zonal Isolation Offshore Malaysia

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 22882, “Advancement of Openhole Gravel Pack and Zonal Isolation With Selective Intelligent Completion in Deepwater Malaysia,” by Elvy Samuel, SPE, Noppanan Nopsiri, and Lee Chan Fong, PTTEP, et al. The paper has not been peer reviewed. Copyright 2023 International Petroleum Technology Conference. _ As fields mature, drilling and completion design and execution for infill development become more challenging. In a deepwater environment, one strategy is to target several reservoir packages in a single wellbore. This technique frequently presents technical challenges, however, because penetrating different zones requires active reservoir management, an allowance for zonal isolation, and an adequate response to potential crossflow. The complete paper presents a completion strategy implemented in an intelligent well completed in the Malaysian deepwater Block K. Introduction The SNP Field is 125 km offshore Sabah in approximately 1350–1400 m water depth. The field crosses the boundary between Block K and Block G, approximately 15 km from the Kikeh floating production, storage, and offloading (FPSO) facility. The field commenced Phase 1 in 2011 with the completion of nine oil producers as openhole gravel packs (OHGPs) and five water injectors with expandable sand screens at the sandface. Phase 2 development, partially covered in the complete paper, commenced in the third quarter of 2021 with three standard oil producers and one smart producer well. All SNP Phase 2 wells were completed as OHGPs targeting various sand reservoirs in a common pressure regime. The well discussed in the complete paper addressed subsurface uncertainties related to depth and the pressure differential between the upper zone (UZ) and the lower zone (LZ) and the isolation requirements of the middle zone (MZ) by implementing an intelligent completion architecture with an OHGP with zonal isolation on the sandface. The flow diversion between the producer zones would be achieved through the deployment of an intermediate completion coupled with an intelligent completion architecture in the upper completion. The well was placed on production in the first quarter of 2022 to the Kikeh FPSO, achieving the targeted rates solids-free. Gravel-Pack Design In this field, the fracture pressure window is marginal, suggesting that a conventional OHGP approach would be challenging. Adding to this complexity is the zonal-isolation requirement. To achieve the objective of complete openhole (OH) coverage and to enable zonal isolation simultaneously, shunt-tube technology was identified as critical. The selection of shunt-tube technology allows the following achievements: - Premature screenout mitigation, because the technique is a proven system that enables the slurry to bypass any restriction in the OH/screen annulus - Zonal-isolation capabilities by combining shunted sand screens and OH mechanical packers with selective shunt-tube isolation capabilities - Application of diverter valves, crucial in fields with marginal fracture pressure windows

Autonomous Drilling Approach Uses Rotary Steerable System in Middle East Wells

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 22975, “Novel Approach to Autonomous Drilling Using Rotary Steerable System in Middle Eastern Oil and Gas Wells,” by Victor Oliveira, Saudi Aramco, and Mohammed Elsadig and Ayman Al-Ghazzawi, SPE, SLB, et al. The paper has not been peer reviewed. Copyright 2023 International Petroleum Technology Conference. Reproduced by permission. _ An operator focused on evaluating and validating a novel approach from its major directional-drilling-service provider using the autocurve-drilling mode to drill curved sections automatically without human intervention. The autonomous curve-drilling technology helped minimize human error, enhance accuracy of well positioning, and improve hole quality for drilling and workover operations. Autocurve-Drilling System Rotary-steerable-system (RSS) intelligence has been improving since its introduction. Around 1990, when the RSS method was introduced, communication with RSS tools was only one-way; downlink commands were sent through flow variations, and the response was monitored. For corrections, human intervention was required by sending new downlink commands. Between 2003 and 2013, downhole automation design and analysis for RSS began with the introduction of closed-loop features in which either verticality or target inclination and azimuth in tangent sections can be maintained. The technology evolved to closed-loop responses in these vertical or tangent modes to adjust the trajectory automatically to the target directions within 0.5° in inclination and 2° in azimuth. The next step for automating the downhole trajectory control of RSS was to close-loop the curve section. This once took increased levels of focus from directional drillers to ensure that they continued reviewing directional responses of the RSS in different intervals to update steering requirements, the steering ratio, and toolface commands. This was a good driver for further improvement of RSS intelligence and updates to desired steering-requirement capabilities to automate curve-section directional control. An autocurve autonomous downhole-automation-control system was developed to address the need to automate curved-section directional control. The intelligent algorithm was developed to change the communication process from including surface intervention to use of only a downhole closed-loop system once directional requirements were established. The system moved away from toolface and steering-ratio downlinking commands to dogleg and toolface commands. As a result, the RSS is no longer dependent on surface intervention for steering requirements but adapts to deliver required dogleg-severity (DLS) commands. This process solved the need for surface dependency. Upon acquiring this information, the tool uses the latest-known inclination and azimuth, and programmed rate of penetration, to create pseudochanges in direction and inclination to follow and automatically calculates a steering ratio to follow the required path. This closed-loop design is performed on a continuous basis within 1 second compared with the average 20-minute process cycle that was used conventionally. Furthermore, the design minimizes the command-downlink requirements to the tool, which further enables the automation path.

Study Investigates Seismic Monitoring for Carbon Storage Leak Detection

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 22980, “Carbon Storage Leak Detection Through Seismic FWI and RTM: Different Survey Analyses,” by Sajjad Amani, Kyoto University. The paper has not been peer reviewed. Copyright 2023 International Petroleum Technology Conference. Reproduced by permission. _ In the complete paper, marine seismic data processing is investigated as a tool for monitoring possible leakages in geological carbon storage. Because of the great importance of storage permanence, a precise leakage-monitoring strategy is crucial. The proficiency of seismic monitoring solutions for leakage monitoring can be affected by shallower layers as a result of structure, seismic wave attenuation, and leak size. The authors explore two popular seismic monitoring methods used in this application in different scenarios: full waveform inversion (FWI) and reverse-time migration (RTM). Introduction Among the various carbon capture and storage (CCS) options, underground storage in saline aquifers is the best-understood solution. To assure storage consistency and permanence, finding the best strategy to precisely detect possible carbon leaks is essential. A perfect method must demonstrate the difference between stored CO2 and injected CO2 to detect potential fast- and slow-leakage areas. The seismic monitoring technique is the most efficient approach in this respect. Two popular tools for seismic monitoring are FWI and RTM. Several studies of their use in this application have been conducted. However, previous research did not analyze different survey arrays for carbon-leak detection using FWI and RTM. The current research aims to investigate quantitative aspects of CCS monitoring to conduct sensitivity analysis of the three different survey arrays [vertical seismic profile (VSP), crosswell, and surface] for different amounts of CO2-storage leakage in a saline aquifer reservoir. The capability of seismic-imaging methods for small amounts of leakage was tested. Comparison of these three arrays using monitoring methods such as RTM and FWI reveals their pros and cons in providing detailed information about the reservoir. In this research, a simple synthetic model was built that closely fits actual reservoirs characterized by suitable physical features such as velocity and density. Subsequently, elastic wave propagation simulation was implemented by use of a finite-difference scheme over a physical model of the reservoir. Then, FWI was applied to enhance the accuracy of the model parameters. With an efficient forward-modeling and inversion scheme, RTM was used as a powerful imaging tool that provides final high-resolution results for monitoring CO2 migration and possible leakage. This process examined the synthetic model for different amounts of CO2 leakage in saline aquifers to evaluate the performance of CO2 leakage monitoring using the seismic method. The results of the different receiver and source arrays also were compared to establish their effectiveness.

Machine-Learning Techniques Classify, Quantify Cuttings Lithology

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 22867, “Automatic Lithology Classification of Cuttings With Deep Learning,” by Takashi Nanjo, Akira Ebitani, and Kazuaki Ishikawa, Japan Organization for Metals and Energy Security, et al. The paper has not been peer reviewed. Copyright 2023 International Petroleum Technology Conference. Reproduced by permission. _ Wellsite geologists spend approximately 70% of their time on cuttings descriptions. In addition, two or three wellsite geologists generally are assigned to a drilling campaign, to be replaced at the end of a shift. Machine-learning (ML) and artificial-intelligence (AI) techniques have the potential to solve these issues because of their advantages in prediction speed, objectivity, and consistency. The authors’ aim is to automate the task of cuttings descriptions with these techniques. A trained model for cuttings description has the potential to realize quantitative, high-speed cuttings description. Methods and Materials Six wells were selected for this study (Poseidon-1, Ichthys2A ST-1, Ichthys2A ST-2, Dinichthys north1, Ichthys north1, and Ichthys north1 ST1). The wells were drilled in the Browse Basin through various lithologies. The authors focused on four lithologies (carbonate, sandstone, mudstone, and volcanic) and collected the cuttings from these lithologies. The total number of cuttings was 160 (21 carbonate, 58 sandstone, 52 mudstone, and 29 volcanic). The cuttings were used in their original dry condition. Each cutting was transported to a Petri plate in a random and sparse layout using tweezers. A stereomicroscope and a digital camera were prepared. Magnification was 6.3X, and picture size was 1,600 pixels in width and 1,200 pixels in height. Pictures were taken randomly, with approximately 20 photographs for each sample. The annotation was conducted by geologists using annotation software. Five label classes were used (sandstone, mudstone, carbonate, volcanic, and background). The total number of annotation data was 1,978. The annotated data were split as training label data, validation label data, and test label data. The pictures were also split as training data, validation data, and test data. The picture and label data were paired. In this study, 1,496 pictures and label data were used as training data sets, 320 pictures and label data were used as validation data, and 162 pictures and label data were used as test data. Four architectures of semantic segmentation were created (PSPNet, Unet, FPN, and Linknet), including two different networks (ResNet152 and EfficientNetB7), and training models were created. The total number of trained models was eight. As a result, the combination of PSPNet and EfficientNetB7 showed the best performance. The combination of PSPNet and EfficientNetB7 was chosen as the architecture of this project. Hyperparameters were chosen in the best practice case. Mean intersection over union (IOU) was used as the model evaluation index.

Plasma-Sprayed Coatings Resist Erosion in Wire-Wrapped Screens

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 21158, “Development of Plasma-Sprayed Coatings To Improve the Erosion Resistance of Wire-Wrapped Screens,” by Lukas Ochmann, SPE, and Mohd M. Amro, SPE, TU Bergakademie Freiberg, and Bernd Gronde, Fraunhofer IKTS Hermsdorf, et al. The paper has not been peer reviewed. Copyright 2021 International Petroleum Technology Conference. Reproduced by permission. _ A newly developed coating is put on the outside (i.e., facing the formation) of standard wire-wrapped screens to make the slots erosion-resistant. The coating consists of ceramic or hard metal and is applied by plasma spraying. An extensive development and verification program was conducted to guarantee defined slot widths, corrosion resistance, and mechanical strength of coating and screen. The coating improves resistance against erosion, can withstand corrosive well environments, and features mechanical properties suitable to be safely installed in any well. Thermal Spraying and Composition of Coatings The screens are coated using thermal spraying. This process uses a hot plasma jet to melt powdery materials and apply them to a solid surface. The molten particles solidify on the surface and form a hard coating with little porosity. No chemical reaction exists between the base material and the coating. Several different steps are necessary to coat a wire-wrapped screen. First, the screen is sandblasted in a distinct way to provide a defined surface roughness. After that, a thin bonding layer is applied by thermal spraying. This intermediate layer further improves the adhesion of the functional layer. This erosion-resistant main layer, which consists of hard metal or ceramic, is applied next by thermal spraying. The coating is finished by filling up the pores of the sprayed layers with a liquid sealer. The coating changes the geometry of the slots, slightly reducing the slot size and creating a less-sharp slot opening. By adjustment of the process parameters of the thermal spraying and choice of the correct initial slot width, defined and constant slot widths can be produced for the final product. Corrosion Investigation All samples and future prototypes are based on 1.4404 (316L) stainless steel. Combinations of four bonding layers, six functional layers, and five sealers were investigated. In total, 237 different samples were corroded under different conditions. The samples were submerged halfway into the brine so that the effect of the three-phase interface (brine, gas, and sample) could be investigated over a period of multiple weeks (minimum 3 weeks, maximum 18 weeks) at 60°C. Further experiments were conducted with nitrogen and hydrogen atmospheres for 3 weeks. The first tests were conducted with samples made from wire-wrapped screens. A second batch of tests was performed with coupons for tensile bond tests.

Automated Work Flow for Sand Prediction, Monitoring Improves Operational Efficiency

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 22989, “An Automated Work Flow of Simplified Representative Elementary Volume Approach to Sand Prediction and Control Monitoring Using Web-Based Interfaces To Reference With Operational Efficiency Improvement in Zawtika Field, Myanmar,” by Supha-Kitti Dhadachaipathomphong, Prapong Sooksawat, and Pooritat Toprasert, PTTEP, et al. The paper has not been peer reviewed. Copyright 2023 International Petroleum Technology Conference. Reproduced by permission. _ The objective of the study described in the complete paper is to increase operational efficiency by using a sand-prediction model to estimate sand production per well based on current operating conditions and to calculate a sand-operating envelope for each well to guide planning and management. The authors found that the simplified representative elementary volume (SREV) approach to sand prediction and control monitoring (SPCM) resulted in an improvement in operational efficiency by reducing time spent on manual analysis and decision-making through dashboards with predictive results. The reader is encouraged to review the complete paper, which contains detailed work flows that include associated equations and steps. Study Objective - Implement SREV approach - Use a sand-prediction model to estimate sand production per well based on current operating conditions - Estimate sand accumulation from the wellhead to the inlet separator dynamically - Predict wall thickness of the main flowlines from the wellhead to the production and test manifold - Forecast sand production when considering changes in reservoir conditions - Use an automated work flow to run the network model and obtain flow conditions, generate the well’s sand-prediction model based on well design and reservoir information, and calibrate the well’s sand-production models based on the latest validated test or sensor data - Implement Web-based interfaces Study Area The Zawtika gas field is in the Gulf of Moattama, Myanmar. A total of 123 wells and 11 platforms was used in the study. Some wells suffer from sand production because the sands are unconsolidated or weakly consolidated from Pliocene to Pleistocene geologic sequences. Sand production causes severe problems such as reduced well productivity and gas potential and damage to surface equipment such as choke, pipeline, and production systems.

Fracture Characterization Explores Potential of Phra Wihan Formation, Thailand

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 22845, “Fracture Characterization and Basement Reservoir Potential of Phra Wihan Formation in Southern Part of Uttaradit Province, Northern Thailand,” by Watcharapong Piewmoh, SPE, PTTEP, and Pitsanupong Kanjanapayont, Chulalongkorn University. The paper has not been peer reviewed. Copyright 2023 International Petroleum Technology Conference. Reproduced by permission. _ The complete paper describes the characterization of fractures in the Mesozoic sandstones of the Phra Wihan Formation in northern Thailand. Fracture characterization of outcrop analogs is important to determine the potential of subsurface reservoirs. The methodology used field study and petrography analysis to determine the relationship of fractures and other structures such as bedding planes and fold geometry. In addition, microstructure analysis can assist in the evaluation of a reservoir’s potential. Introduction Basement reservoir sandstones are one of the main targets in a mature onshore oil field in Thailand. But most basement reservoirs of the onshore Tertiary basin are pre-Tertiary and are associated with low quality. Prediction of reservoir quality in low-porosity and -permeability conditions requires an understanding of fractures in the subsurface. Outcrop analogs are key in characterizing fractured reservoirs. Geological Setting The tectonic evolution of Thailand is detailed in the complete paper. The country’s primary geological provinces are subdivided into the following five components, from west to east: - Sibumasu terrane - Inthanon zone - Sukhothai terrane - Nan and Sra Keao sutures - Indochina terrane The Sibumasu and Indochina terranes are major continental masses that collided during the Devonian-Triassic. Two subparallel suture zones exist along the convergence between the Sibumasu and Indochina terranes; one is an accretionary complex defined by the Inthanon zone. Another is a closed back-arc basin defined by the Nan and Sra Keao sutures. The Sukhothai terrane is an island-arc system formed along the margin of the Indochina terrane.

Technology Focus: Wellbore Tubulars (July 2023)

Corrosion is a pervasive issue that affects oil and gas production. It poses a significant threat to the safety and integrity of oil and gas equipment, and it can lead to costly repairs and downtime. Mitigating corrosion is a crucial part of maintaining the productivity and safety of oil and gas operations. The first paper in the Wellbore Tubulars Technology Focus feature, IPTC 21818, explores the prevalence of corrosion in the oil and gas industry and the strategies used to mitigate its effect, including use of alternative materials and their qualification. The second paper in the feature, SPE 206340, deals with stuck-pipe incidents, a major cause of economic losses, safety hazards, and nonproductive time. With the use of artificial intelligence (AI) and machine learning (ML) techniques, however, these incidents can be prevented by analyzing drilling data. In recent research presented at the International Petroleum Technology Conference and other SPE conferences, various AI and ML models were developed to predict and prevent pipe-sticking symptoms. The authors of the paper used natural language processing applied to drilling memos to improve the accuracy and robustness of kick and lost-circulation detection. Finally, paper OTC 31160 discusses the use of microelectromechanical systems technology to embed sensors in tubulars that measure temperature and pressure throughout a well’s life. With low power consumption and an adapted transmission technology, this technology can be used to access previously inaccessible well areas in real time. Such technological strides in wellbore tubulars are revolutionizing the oil and gas industry by providing real-time data and making new areas of wells accessible. With the integration of intelligent pipe technology, nonmetallic casing strings, and powered wired drillpipe solutions, operators can better monitor their wells, adjust production parameters, and ensure the safety of their installations. These advancements are a significant step forward for the industry and are sure to have a positive effect on well integrity and safety for years to come. Recommended additional reading at OnePetro: www.onepetro.org. SPE 202498 No Pipe Body Downgrades—Improved Corrosion Mitigation Coating System Provides Significant Operator Savings by Buck Johnson, Chevron, et al. SPE 205468 The Environmental Benefits of Repurposing Tubular Steel From North Sea Oil and Gas Fields by Rob William John Holdway, Giraffe Innovation, et al. IPTC 21455 Performance Improvement of Wells Augmented Stuck-Pipe Indicator by Model Evaluations by Meor M. Meor Hashim, Petronas, et al. IPTC 22660 First Successful Deployment of Nonmetallic Casing Strings: A Case History by Fauzia Waluyo, Saudi Aramco, et al.

Study Investigates Conversion of Biomethane From CO2 and Biohydrogen

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 22744, “Accelerated Methanogenesis for the Conversion of Biomethane From Carbon Dioxide and Biohydrogen at Hyperthermophilic Conditions,” by Ivy C.C. Hsia, Petronas, and Mohd F.A. Wahab and Nur K.A. Jalil, Universiti Teknologi Malaysia, et al. The paper has not been peer reviewed. Copyright 2023 International Petroleum Technology Conference. Reproduced by permission. _ Methanogenesis is the conversion of CO2 to methane (CH4) using microbes. In the context of CO2 usage, the process of methanogenesis using native microbes from a particular reservoir can be a very slow process without any external intervention. The study detailed in this complete paper investigates the use of agriculture byproducts such as palm oil mill effluent (POME) as substrates, along with potential microbial isolates that can produce biohydrogen at high temperatures. The authors write that stimulation of microbes using POME as substrate with hydrogen (H2)/CO2 supplementation is important in accelerating the rate and yield of CH4 production. Introduction The authors write that a population of microbes isolated from sludge of agriculture wastes, when given proper conditions and nutrients, was able to accelerate the rate of methanogenesis. POME is an agricultural byproduct from which a huge microbial community can be manipulated for methanogenesis, specifically for hydrogen production. This study incorporates the process of dark fermentation, using POME to generate hydrogen required to convert CO2 to CH4 in a syntrophic reaction at hyperthermophilic temperatures. Accounting for both the high reservoir temperatures (above 100°C) common to Malaysia and the temperature-tolerance limit of most microorganisms in general, the authors selected 70°C as the temperature to be studied. They write that, as their team studied a range of different temperatures, anaerobic microbes showed no production of biohydrogen and CH4 above 70°C.

Machine Learning Approach Empowers Well Placement in Tight Gas Field

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 22188, “Machine-Learning-Empowered Well Placement in a Large Unconventional Tight Gas Field in China,” by Ting Yu, SLB; Xiangzeng Wang, Shaanxi Yanchang Petroleum; and Alexis Carrillat, SLB, et al. The paper has not been peer reviewed. Copyright 2022 International Petroleum Technology Conference. Reproduced by permission. _ A tight gas field produces gas from a large heterogeneous fluvial reservoir with limited well control in margins and appraisal areas and sparse advanced logs. The principal goal of the study described in the complete paper was to provide a novel solution using machine-learning (ML) techniques to predict sandstone distribution and, to some extent, automate the process of optimizing well placement. The presented work flow overcomes low data quality, scaling, and inconsistency and builds the bridge between geoscience and artificial intelligence (AI) software platforms. Introduction The field is an unconventional gas reservoir covering a vast area in the Ordos Basin in China. This field produces gas from a complex and heterogeneous fluvial reservoir with limited well control for prediction of sand-body distribution. Reservoir distribution and quality prognosis carry large uncertainties. The well spacing between exploration and appraisal wells is approximately 3–4 km; well control is sparser in resource-overlaying areas. As such, reservoir prediction using only well data is marked by uncertainties and can result in high geological risk in placing development wells. In addition to well data, 2D seismic lines cover the full field with a spacing of 2×4 km. The described work flow aims to use all geological and geophysical (G&G) information effectively to optimize well placement and minimize risk of dry wells. It can combine G&G software and AI platforms to deepen data mining and analyze correlations between the seismic waveform and sandstone distribution. This is achieved by using advanced ML algorithms to construct a 3D heterogeneity model with multiple variables. It enables quick organization of data for analysis and interpretation and becomes a tool for supporting real-time drilling. Objective The challenge in this fluvial reservoir is to replicate the sand-body-stacking relationships based on sparse and multiscale data integration. With that objective in mind, ML is an effective tool to automate geoscience work flows. In this study, a new work flow was created that takes advantage of ML in subsurface modeling for efficient and computationally inexpensive forecasting. This method incorporates ML in the context of decision support. The main objectives of the study include the following: - Automatically classify seismic attributes into waveforms and establish their correspondence to log motifs - Improve the effectiveness of 2D seismic data integration with well-log data - Generate a reservoir risk map based on seismic and log-data integration - Construct an advanced 3D geological model with multiple variables - Generate a more-objective interpretation by having less human inference in the data analysis - Bridge the gap between G&G and AI software platforms and lift current G&G software limitations This enabled use of advanced decision-tree-based ML algorithms to generate a geological model.

Material Selection and Corrosion Rate Analyzed for CO2 Injection Well

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 21818, “Material Selection and Corrosion-Rate Analysis for CO2 Injection Well: A Case Study of K1 Field CO2 Sequestration Project,” by Mohd A. Abu Bakar, Wan Amni Wan Mohamad, and M. Wahidullah M. Wahi, Petronas, et al. The paper has not been peer reviewed. Copyright 2021 International Petroleum Technology Conference. Reproduced by permission. _ Typical materials used for CO2 injector wells are either corrosion-resistant alloys (CRA) or epoxy-lined tubulars. The most widely adopted CRA material is 25Cr, which features a high well-application cost. Application of materials other than 25Cr for CO2 injector wells are uncommon but may be fit for purpose. The complete paper describes material-selection methodology and corrosion studies performed in the K1 field CO2 sequestration project using materials other than 25Cr in an effort to optimize well costs and improve overall project economics without jeopardizing CO2 injector-well integrity. Introduction K1 field is in the Sarawak Basin at a water depth of 453 ft. It was discovered by an exploration well in 1972 and appraised by a dedicated well in 1992. The field features a gas column of 324 ft from the free water level at 4,990 ft true vertical depth subsea. Gas initially in place for this field is estimated at approximately 2,800 Bscf. CO2 storage screening studies had identified an opportunity to use the K1 field as a storage site. The source of CO2 gas is a nearby field, from which separated CO2 gas will be transported through a 130-km pipeline to the K1 field’s new injection-wellhead platform. The current plan is to inject and store the CO2 inside one of the depleted carbonate reservoirs until an increase in reservoir pressure to the initial pressure of 3,440 psi is observed. The reservoir temperature is approximately 120°C. Injection-Fluid Composition and Presence of Water Injection fluid contains a high mol% of CO2, methane, and other impurities such as nitrogen and hydrogen sulfide (H2S) gases. Injection fluid will be injected above the CO2 supercritical condition. Based on the injection fluid’s composition, CO2 will be the main source of corrosion in the presence of water when exposed to unprotected tubulars in the wells. The presence of H2S denotes the effect of stress corrosion cracking (SCC) and sulfide stress cracking (SSC), which must be considered in selecting tubing material for the injector wells. A small percentage of water (approximately 0.0086 mol%) also exists in the injection fluid. This will be detrimental to the injection wells in terms of corrosion if it is in the aqueous phase. To study this, the well’s shut-in and injection pressures and temperatures were plotted against the water-phase diagram. During these conditions, water in the injection fluid exists as vapor phase. Considering the possible risks of a higher percentage of water in the injection fluid, a more- conservative approach was taken in the selection of tubing material for the injector wells.

Efforts Lead to Formulation of High-Performance ASP

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 22729, “ASP Formulation Development Journey: Optimization, Validation, and Quality Control for Mangala Field,” by Nitish Koduru, Dhruva Prasad, SPE, and Amitabh Pandey, SPE, Cairn Oil and Gas. The paper has not been peer reviewed. Copyright 2023 International Petroleum Technology Conference. Reproduced by permission. _ Mangala is a large low-salinity, high-quality fluvial oil field in India with stock-tank oil initially in place (STOIIP) of more than 1 billion bbl of waxy and moderately viscous crude. Aqueous-based chemical enhanced oil recovery (EOR) has been identified as the most suitable technique to improve recovery over waterflooding. The objective of the complete paper is to describe alkaline/surfactant/polymer (ASP) formulation development for Mangala, which involved more than 30 corefloods at the time of writing, with formulation design changing over time. Field Background The Mangala field has been regarded as an excellent chemical EOR candidate since its discovery in 2004. The main reservoir unit is divided into the Lower and Upper Fatehgarh formations. These units are subdivided into five reservoir units, FM1 to FM5 from top to bottom. Mangala contains waxy sweet crude oil with gravity ranging from 20 °API near the oil/water contact to 28 °API in the oil column. The crude has in-situ viscosity of 9–17 cp. The crude has good napthenic acid content and reacts with alkali to produce in-situ soap. Immediately after the field’s appraisal stage, work to identify the most suitable EOR process began. First, a polymerflooding pilot was conducted during 2011–12. The encouraging results led to full-field polymerflooding implementation in November 2014. The ASP pilot performed well; incremental oil recovery over polymerflooding was estimated to be in the range of 20–25% of the pilot STOIIP. The initial development plan involved implementing a hot waterflooding production startup to maintain reservoir pressure and effective sweep. The Upper Fatehgarh FM1 and FM2 units were developed with inverted nine-spot patterns, while the more-homogeneous lower Fatehgarh (FM3 and FM4) were developed with downdip injectors and updip horizontal producers. The Mangala field began producing under a hot waterflood in 2009, with the injected water heated to approximately 80–85°C to avoid wax deposition. Injection was started within a few months of first production. At the time of writing, the field is under polymerflooding, with results largely in line with expectations. The field, which has already produced approximately 37% of the STOIIP, is on a declining production trend, and large-scale ASP flooding is being considered as the next development initiative to arrest production decline and increase overall recovery. The complete paper discusses EOR screening studies; ASP formulations, including the initial formulation; the method adopted for selection of chemical suppliers for the pilot test; optimization of ASP formulations tested in the pilot; validation of the developed formulation to other layers of the field; and planned quality-control processes to be used during procurement of chemicals for larger applications of ASP floods in the field. This synopsis concentrates on the last three of these factors, rather than the formulations considered, which, in addition to the initial formulation, included the following: - Formula 2: ASP formulation with a sacrificial surfactant - Formula 3: ASP formulation with a single surfactant - Formula 4: Formulation with a highly hydrophilic, large-hydrophobe surfactant