Improved Hydrocarbon Recovery Research Articles

Investigating the Bubble Point Pressure Discrepancy by History Matching for Mishrif Reservoir, Southern Iraqi Oil Field

Carbonate reservoirs have been a primary focus for academics and oil and gas companies for many years. However, the complex nature of these rocks has always posed challenges. This is particularly true in the study area, which is located in the unstable Mesopotamian Basin, where multiple oil fields produce hydrocarbons from NW-SE-trending anticlines along the Zagros Fold-Thrust Belt. The primary goal of reservoir simulation is to forecast reservoir performance and apply different techniques to improve hydrocarbon recovery under different conditions. The study area faces a problem of discrepancy in the bubble pressure at the same reservoir unit, which is attributed to the faults in the Mishrif reservoir. A study was conducted to investigate the causes of this phenomenon. The proposed method for verification involves simulating history matching using the Petrel platform after building two geological models on the probability of the fault and the reef; as a result of seismic survey interpretation. Field data for gas production of the reservoir and Pressure-Volume-Temperature analyses, especially the wells (well pad F), were used to determine the causes of the discrepancy. The current study found that the calculated and observed data match more consistently in the case of the fault rather than in the case of the reef, indicating the presence of fault in the area near the well pad F. This caused compartmentalization, leading to the discrepancy in the bubble pressure. This study could significantly improve regional exploration, especially in Iraq.

Improving Hydrocarbon Recovery in the Presence of Stringent Environmental Regulations Through Novel Conformance Control: Carbonate Reservoir Scenario

Improving Hydrocarbon Recovery in the Presence of Stringent Environmental Regulations Through Novel Conformance Control: Carbonate Reservoir Scenario

Technology Focus: EOR Modeling (January 2024)

The oil and gas industry is at a critical juncture in addressing the pressing need to balance operational efficiency with environmental stewardship. With the world’s growing emphasis on climate change and sustainability, the industry is tasked with the dual objectives of refining operational efficiency and simultaneously diminishing its carbon footprint. This balancing act has become a strategic imperative crucial for the long-term viability of the industry. In light of the recent COP28 agreement, which emphasizes a “swift, just, and equitable energy transition,” the role of low-emission enhanced oil recovery (EOR) and operational optimization becomes increasingly significant. This period of transition, which may span several decades, demands a pragmatic approach where the existing hydrocarbon resources are used as efficiently and responsibly as possible. In the quest to optimize operations and reduce carbon footprint, three innovative technical papers present a cohesive story of advancement through modeling and machine learning. These papers underscore the industry’s shift toward more efficient practices, each contributing a crucial piece to the larger puzzle of EOR.The first paper introduces an advanced modeling approach for fractured reservoirs, a significant development in tight rock simulations that simplifies fracture heterogeneity characterization and enhances computational efficiency, crucial for optimizing asset development decisions in shale and tight oil resources. Building on the theme of efficiency, the second paper pivots to the realm of surfactants, exploring their role in wettability alteration within unconventional liquid-rich reservoirs. This research provides a systematic approach for screening thermally stable surfactants under reservoir conditions, crucial for improving hydrocarbon recovery without unnecessary field trials. The final piece of this narrative is a study using machine learning to predict gas-injection parameters in EOR processes. This approach addresses the lack of extensive gas-injection laboratory data, demonstrating the power of data-driven predictions in enhancing operational efficiency and decision-making. These papers weave a compelling narrative of technological innovation, highlighting the role of advanced modeling and machine learning. As the oil and gas industry progresses in its vital mission to supply the world’s energy needs, the pivotal role of technology innovation becomes increasingly evident. Advanced technologies focused on operational optimization and reducing carbon emissions are essential in reinforcing the industry’s adaptability and resilience in the context of this rapidly evolving energy landscape. Recommended additional reading at OnePetro: www.onepetro.org. SPE 215083 An Analytical Tool to Predict Fracture Extension and Elastic Desaturation for Polymer Field Projects by M.B. Abdullah, The University of Texas at Austin, et al. SPE 216822 First Pilot Design of Low-Tension-Gas (LTG) Flooding in Carbonate Field in North Oman by Mohammed Al-Abri, Petroleum Development Oman, et al. SPE 213037 Field-Scale Multistage and Multiobjective Optimization of Rate and Concentration for Polymer Flooding by Ruxin Zhang, Texas A&M University, et al.

Lateral Rock Characteristic Evidence of Hydrocarbon Restoration from Post-Stack Impedance Inversion: A Case Study of ZED-field Offshore Niger Delta

Lateral predictions of rock properties that are descriptive of a reservoir have been studied using a model-established seismic inversion approach that was used to convert input seismic data into an acoustic impedance structure to optimize hydrocarbon restoration in the field. This was actualized by integrating wireline logs and 3D post stack seismic data procured from ZED-Field offshore Niger Delta. The inversion system employed in this study comprises of forward modelling of reflection coefficients starting with a low-frequency impedance model induced from well logs and convolution of the reflection coefficients with the source wavelet extracted from the seismic input. P-impedance analysis at reservoir C5000 delineated from the control well gave a near perfect correlation of 0.998109 (≈ 99.8 %) between the original P-impedance log, initial P-impedance model log and inverted P-impedance log with an estimated error of 0.0616932 which is about (6.16%). Seismic inversion analysis realized an acoustic impedance structure with P-impedance values ranging from 3801 to 11073.0m/s*g/cc and having an overall increase with depth tendency. Specifically, a low-impedance structure was observed at the reservoir window that can be profiled laterally elsewhere from the existing wells. Impedance slices extracted from the impedance volume at the top and base of reservoir C5000 clearly showed low impedance values away from the existing wells which are evidence of new hydrocarbon prospects (hydrocarbon-charged sands) in the field that can be explored for improved hydrocarbon recovery and field development. Therefore, the realized attribute could supply litho-fluids knowledge inside the current reservoirs, and likewise aid in defining probable hydrocarbon regions of low impedance that can be tested with the input seismic to boost the interpretation of reservoir attributes with feasible integration to seismic stratigraphy for improved reservoir prediction away from the extant wells. This information can be invaluable in delineating more prospective reservoir zones in the field, and thereby enhancing optimum field development which aids in reservoir management decisions.

A new insight on relative permeability modifier as conformance control in carbonate reservoir

The primary issue of high-water cuts in exploiting carbonate fields poses significant challenges and requires an immediate solution. The approach to tackle the root cause of this problem is reservoir conformance control. Conventional conformance control treatments, such as polymer-based materials, are ineffective and incompatible with the unique properties of carbonate reservoirs. Textural heterogeneity in carbonate leads to heterogeneity in the distribution of storage and flow properties that may govern changes in saturation patterns. The percolation of gas-water flow in carbonate highly depends on the pore structure. Conformance control refers to managing fluid movement within a reservoir to optimize production and reduce unwanted fluid production. The major challenge of water conformance control for carbonates using chemical treatment is the compatibility of the polymer system with the rock and fluid settings. This paper reviews current research on conformance control methods, including chemical and mechanical techniques. The effectiveness of various conformance control methods was evaluated based on their ability to improve sweep efficiency, reduce water production, and increase hydrocarbon recovery in different reservoir types. The review also discusses the challenges of implementing conformance control techniques, such as formation damage and fluid mobility issues. Overall, the paper concludes that successful implementation of conformance control strategies requires a thorough understanding of reservoir characteristics and planning to ensure optimal results. The findings of this study provide valuable insights into developing effective conformance control techniques that can improve hydrocarbon recovery and optimize reservoir performance. The results of this study provide critical insight into using efficient and operationally low-risk materials to reduce water cuts in the strong water drive carbonate reservoir.

Utilizing integrated artificial intelligence for characterizing mineralogy and facies in a pre-salt carbonate reservoir, Santos Basin, Brazil, using cores, wireline logs, and multi-mineral petrophysical evaluation

In complex carbonate reservoirs, it is crucial to understand the connections between reservoir compositions (minerals, facies, and properties). Conventionally, core samples have been used to measure reservoir parameters and identify minerals and facies. However, core samples are limited to certain wells. Therefore, additional techniques are necessary to overcome this limitation comprehensively. This study aims to identify key mineralogical and facies components of the Barra Velha Formation (BVF) and their relation to reservoir parameters. Dolomite, calcite, quartz, and clay minerals were commonly found using X-ray Diffraction (XRD). By employing multi-mineral (MM) petrophysical evaluations, we accurately recreated mineral quantities from XRD and petrophysical properties from core analysis to ensure reliability. Replications of inputs well logs and the mineralogical volume from spectroscopic (ECS) were used as reliability techniques for validating the MM. A total of 47 wells were analyzed using those methods. In this study, the classification of facies was accomplished through the selection of three prominent supervised artificial intelligence techniques, among which SOM, a widely employed method for facies estimation, was included. Additionally, the ensemble methods of Random Forest and XGBoost were adopted due to their recognized efficacy in handling tabular data and their track record of success in machine learning and artificial intelligence competitions. Remarkably, the performance evaluation revealed that Random Forest and XGBoost algorithms outperformed SOM, yielding the most favorable outcomes in this context. An integrated analysis of mineralogical and facies results was conducted, incorporating production data and special profiles such as nuclear magnetic resonance (NMR) and Wellbore Image (WBI) to identify vug-containing areas. The dolomitic facies exhibited favorable reservoir qualities, influenced by diagenetic processes represented by vuggy porosity, which enhanced permeability. Shrubstones, spherulites, and reworked facies showed superior petrophysical qualities and were connected with productive regions, leading to elevated dolomite concentrations, and vuggy abundance. The study highlights two major innovations: the use of mineralogical volume from multi-mineral assessments as inputs for AI-based property estimation to improve facies estimates, and the discovery of relationships between facies, minerals, and reservoir properties, compared to production data. This understanding allows for more accurate static model creation, optimal production interval selection, improved hydrocarbon recovery, and better specification of stimulation processes.

Surfactant technology for improved hydrocarbon recovery in unconventional liquid reservoirs: a systematic literature review

An unconventional liquid reservoir (ULR) is a type of underground geological deposit containing liquid hydrocarbons, such as crude oil, natural gas liquids, or condensate, not found in traditional oil and gas reservoirs. These formations have distinct properties that make oil and gas production more difficult than in typical reservoirs. Surfactants can be added to the fracking fluid to aid in the release of hydrocarbons. By reducing the amount of water and chemicals used in the process, surfactants can assist to reduce some of the negative environmental implications associated with fracking. In the current study, a systematic literature review was used to analyze and identify existing literature on surfactant technology in unconventional liquid reservoirs from the previous five years. 12 papers out of the 500 papers collected showed that studies had been performed and proved that surfactants can potentially increase the recovery of unconventional liquid reservoirs. The mechanism behind the positive outcome was concluded to be the alteration of wettability of reservoir rock and interfacial tension. Based on the conducted review, evaluation of the environmental impact from the use of surfactant and assessment of economic feasibility of surfactant technology in ULR could be the future research topics.

Adsorption characteristics, isotherm, kinetics, and diffusion of nanoemulsion in tight sandstone reservoir

Nowadays, nanoemulsions have shown a high application potential in improving hydrocarbon recovery from tight reservoirs. However, the adsorption characteristics, isotherms, kinetics of nanoemulsions onto reservoir rocks surface and the diffusion behavior into reservoir matrix are still not been systematically clarified. In this work, nanoemulsion was prepared by diluted microemulsion method using two nonionic surfactants, isopropanol, limonene and 2.0 wt% KCl solution. The static adsorption capacity measurement under different influencing factors were carried out, and the adsorption process was characterized through equilibrium isotherms and kinetic studies. Also, the diffusion behavior of nanoemulsion in the sandstone reservoir matrix were evaluated by core flooding experiments. Results indicated that the nanoemulsion was successfully synthesized and the droplet size mainly distributed between 8 and 18 nm. It had been found that the optimal static adsorption experimental parameters for 0.1 wt% nanoemulsion were 1:8 solid–liquid ratio and 50/60 mesh rock powder. Equilibrium adsorption results indicated that Langmuir model yielded a better fit which means that single-layer coverage of the surfactants composed of nanoemulsion onto the rock surfaces was more probable. Meanwhile, it was concluded that the pseudo-second order model could better describe the kinetic behavior of nanoemulsion adsorption onto the rock surfaces, which revealed that the adsorption rate was positively correlated with the nanoemulsion concentration. Dynamic adsorption experiments showed that the adsorption amount is inversely proportional to the core permeability, while the diffusion coefficient increases with the increase of permeability. Moreover, the advantage of nanoemulsions over sole surfactant is that the oil nucleus in the nanoemulsions enable control the release of the attached surfactants, and there is a competitive adsorption relationship between oil nucleus and rock surface for the free surfactants in the solution, which offers a possibility for reducing the surfactant adsorption loss and extending the invasion distance in the reservoir matrix. The findings obtained in this study can help for better understanding of the interaction mechanism between nanoemulsions and reservoir rocks, and provide guidance for selecting appropriate nanoemulsions for the enhanced oil recovery (EOR) project in tight sandstone reservoirs.

The Impact of Formation Anisotropy and Stresses on Fractural Geometry—A Case Study in Jafurah’s Tuwaiq Mountain Formation (TMF), Saudi Arabia

Multi-stage hydraulic fracturing (MsHF) is the main technology to improve hydrocarbon recovery from shale plays. Associated with their rich organic contents and laminated depositional environments, shales exhibit transverse isotropic (TI) characteristics. In several cases, the lamination planes are horizontal in shale formations with a symmetric axis that are vertical to the bedding plane; hence, shale formations are known as transverse isotropic vertical (TIV) rocks. Ignoring the TIV nature of shale formations leads to erroneous estimates of in situ stresses and consequently to inefficient designs of fractural geometry, which negatively affects the ultimate recovery. The goal of this study is to investigate the effects of TIV medium characteristics on fractural geometry, spacing, and stress shadow development in the Jurassic Tuwaiq Mountain formation (TMF) in the Jafurah basin, which is a potential unconventional world-class play. This formation is the main source for prolific Jurassic oil reservoirs in Saudi Arabia. On the basis of a petrophysical evaluation in the Jafurah basin, TMF exhibited exceptional unconventional gas characteristics, such as high total organic content (TOC) and low clay content, and it was in the proper maturity window for oil and gas generation. The unconventional Jafurah field covers a large area that is comparable to the size of the Eagle Ford shale play in South Texas, and it is planned for development through multi-stage hydraulic fracturing technology. In this study, analytical modeling was performed to estimate the fractural geometry and in situ stresses in the anisotropic medium. The results show that the Young’s modulus anisotropy had a noticeable impact on fractural width, whereas the impact of Poisson’s ratio was minimal. Moreover, we investigated the impact of stress anisotropy and other rock properties on the stress shadow, and found that a large stress anisotropy could result in fractures being positioned close to one another or theoretically without minimal fractural spacing concerns. Additionally, we estimated the fractural aspect ratio in different propagation regimes and observed that the highest aspect ratio had occurred in the fractural toughness-dominated regime. This study also compares the elastic properties and confirms that TMF exhibited greater anisotropic properties than those of Eagle Ford. These findings have practical implications for field operations, particularly with regard to the fractural geometry and proppant placement.

Compatibility Coreflood Studies Explore Formation Damage in Tight Reservoirs

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 207764, “Case Study of Identifying and Minimizing Formation Damage in Tight Reservoirs Caused by Drilling Fluids in Abu Dhabi Onshore Operation Using Compatibility Coreflood Studies,” by Raymond Saragi, Mohammad Husien, and Dalia S. Abdullah, ADNOC, et al. The paper has not been peer reviewed. _ The authors examine formation-damage mechanisms caused by drilling fluids in tight reservoirs in several onshore Abu Dhabi oil fields. Three phases of compatibility corefloods were performed to identify the potential of improving hydrocarbon recovery and examine reformulated or alternate drilling muds and treatment fluids. The compatibility corefloods on tight reservoir cores, along with high-resolution quantifications and visualizations, identified damaging mechanisms and helped identify potential to improve hydrocarbon recovery and treatment-fluid options. Introduction The operator examined drilling-mud performance for UAE fields including Bab, Rumaitha, Qusahwira, Sahil, and Mender. Results appeared to be good in high-permeability zones but not in lower-permeability zones. A multiphase compatibility study consisting of a series of coreflood simulations analyzed both producer and injector wells, but the complete paper focuses on the producer wells. The use of nano-computed tomography (CT) scans and cryogenic scanning electron microscope (SEM) with energy dispersive spectroscopy (EDS) as interpretative tools provided insights into the coreflood results (55 of which are presented in the complete paper). The reservoirs consist of Lower Cretaceous carbonate sediments. This study examined lower-permeability zones; the results shown in the complete paper are only from the tight samples below 15 md. The samples used in the study are detailed in Table 1 of the complete paper and represented the following reservoirs: - Bab (wells coded BB-1, BB-2, BB-3, BB-4, BB-5, BB-6, and BB-7; 0.1–15-md gas permeability) - Mender (well coded MN-1; 3–12-md gas permeability) - Qusahwira (wells coded QW-1 and QW-2; 0.5–1-md gas permeability) - Rumaitha (well coded RA-1; 2–15-md gas permeability) - Sahil (well coded SA-1; 2–4-md gas permeability) Methodology Coreflood simulations were performed using specialized equipment capable of executing the study at reservoir conditions while eliminating artifacts such as corrosion. Accurate replication of reservoir conditions is important, especially where potential scaling exists. Phase 1 examined permeability alterations and damaging mechanisms after application of the currently used drilling mud. The methodology is detailed in the complete paper, but the authors emphasize the use of interpretive tools in this process. Phase 2 examined a series of reformulated and alternate drilling muds. Following the results of Phase 1, the current field mud was reformulated and examined as Reformulated Mud Formulation 1 alongside three alternate drilling muds from separate vendors. Phase 3 built on Phases 1 and 2 by examining the incorporation of a displacement or treatment fluid as part of the operational sequence. The methodology for Phase 3 was similar to that used in the previous phases, with the addition of treatment-fluid application before drawdown.

A new developed thermal model to predict formation failure in vertical wells during steam injection

As production from mature fields declines, finding technologies to improve hydrocarbon recovery is becoming extremely important in oil and gas industry. In this regard, steam injection through injection wells has proven to be an effective method for increasing oil recovery in heavy oil reservoirs. The implementation of this approach, however, raised the issue of wellbore instability due to the introduction of thermal stresses in the formations around the injection wells. In this work, a new stability model that covers the effect of thermal stresses and considers three-dimensional rock failure mechanism has been established for vertical wells. The developed model has been verified in two field cases. The model results have shown a good match with the actual field observations. The results of the study show that applying steam injection will lead to a significant dropping in the stability of the formations that can be predict by the developed geomechanical model. [Received: November 18, 2021; Accepted: May 18, 2022]

Thinning of Botryococcus braunii Colony Sheath by Pretreatment Enhances Solvent-Based Hydrocarbon Recovery

Botryococcus braunii is a green microalga that is attracting attention as an alternative aviation fuel owing to its hydrocarbon production. In this study, we investigated two approaches to reducing the energy required by pretreatment for hydrocarbon recovery by solvent extraction. Saltwater culture has been reported previously only for the B race of Botryococcus braunii; it improved hydrocarbon recovery from the A race too. We developed a hot water rinsing method that reduced the temperature requirement from the 85 °C which was previously reported for the B race. As the salt concentration in the medium increased, the colony sheath that covered the entire colony surface of the Yamanaka strain (race A) became thinner and the hydrocarbon recovery increased. Saltwater culture can be applied to race A without any energy input. Hydrocarbon recovery from the Showa strain (race B) exceeded 90% after nine rinses with 70 °C hot water while maintaining this temperature. Thus, both pretreatments lowered the treatment temperature by at least 15 °C compared to previously reported methods. Both treatments improved hydrocarbon recovery by thinning the colony sheaths.

Microbial induced mechano-petrophysical modified properties to improve hydrocarbon recovery in carbonate reservoirs

This study focuses on the impact of a microbial-induced process on mechanical and petrophysical properties of tight carbonate hydrocarbon reservoirs and its implication for hydrocarbon recovery from carbonate reservoirs. Tight carbonate core samples were treated with cultured microbial media of Clostridium acetobutylicum at 42 °C for 14 days. The before- and after-treatment mechanical (unconfined compressive strength, UCS; fracture toughness, Ks) and petrophysical (porosity and permeability) properties of the core samples were investigated and analyzed. The scratch test method was used for assessing the geomechanical properties. The results indicate that in tight carbonate reservoirs, post-treatment microbial-induced alterations could degrade its mechanical integrity with −30% UCS and −28% Ks. The post-treatment improvement in petrophysical properties of the tight carbonate rocks yielded a 355% increase the porosity and ＋734% in permeability. The application of the technology presented in this study can potentially enhance the susceptibility for induced fractures to nucleate and propagate during reservoir stimulation in tight carbonate reservoirs, and enhance flow pathways to improve hydrocarbon recovery. This study provides insight into microbial-induced alteration technology that can be incorporated with other reservoir-stimulation techniques to further enhance hydrocarbon recovery from carbonate reservoirs.

Effect of Pore Structure and Capillary Number on Gas-Water Flow Patterns in Carbonate Rocks

Summary Rock pore structure and capillary number determine gas-water flow through limestone. Limestone is of key importance for natural gas production and gas storage; however, there is still limited direct evidence on the precise influence of the pore space morphology (vugs, fractures, and homogeneous pore matrix) and capillary number. Here, we thus studied gas-water flow patterns in various limestones via in-situ X-ray microtomography combined with numerical flow simulations. Pore structure heterogeneity significantly affected the fluid migration path. Gas flowed rapidly through large pores and vugs but flowed slowly through microfractures. In contrast, water flowed through microfractures and small pores but did not enter large pores at low capillary number conditions. Water flow simulations [performed for different capillary numbers directly on microcomputed tomography (μ-CT) images] demonstrated that snap-off and dead-end corners controlled the distribution of residual gas, consistent with the experiments. In addition, the simulations showed that less residual gas distributed around dead-end corners at a low capillary number, and a part of the residual gas can be displaced by increasing viscous forces. Moreover, a power-low relationship between gas cluster volume and surface area was observed, and the gas cluster size distribution could also be fitted with a power-law correlation. In all types of tested limestones, the power-law exponents (p ≈ 0.77, τ ≈ 0.86) were lower than that predicted by simple percolation theory (which predicts p ≈ 1, τ ≈ 2.189). There was evidence that a simple percolation model was unlikely to provide reliable predictions in homogeneous porous media, and we further extended the application scope of this conclusion to heterogeneous porous media. This work therefore provides fundamental data and improves fundamental understanding of gas-water flow through limestones and aids in the further advancements of improved hydrocarbon recovery and gas storage in limestone reservoirs.

Workshop Review: Digital rock physics: From pore to reservoir scale

With continuous optimization of reservoir performance in the oil and gas industry globally, there are outstanding technical challenges that require development and implementation of technologies and methodologies. One of the main challenges is how to build a static reservoir model that integrates rock-property heterogeneity to derive dynamic reservoir models and improve hydrocarbon recovery. Rock properties are measured at different scales by using advanced measurements ranging from 3D surface seismic inversion to log data and core data. The advancement of rock digital imaging has been proven to enhance interpretation results. Digital rock physics plays a vital role by utilizing new technologies such as machine learning to get the best outcome.

Probing oil recovery in shale nanopores with small-angle and ultra-small-angle neutron scattering

Increasing oil production from unconventional shale reservoirs is crucial to meet growing energy demands while achieving lower carbon emission than conventional crude oil. Enhanced oil recovery (EOR) has been proposed to improve hydrocarbon recovery rates through the injection of a fluid into the reservoir to facilitate residual oil release from the shale formation. However, economical and sustainable implementation of EOR requires advanced knowledge of fluid behavior in nano-sized pore spaces in shale. In this study, we utilize small-angle neutron scattering (SANS) and ultra-small-angle neutron scattering (USANS) as experimental probes to examine decane removal from a shale nano- to micro-porous matrix, utilizing methane as the injectant. The extent of decane saturation and recovery post-methane pressurization is quantified for clay-rich and carbonate-rich shale samples. A key finding is that extraction of decane by methane on depressurization is related to the methane-decane critical point. Furthermore, we found that although clay-rich shale had a much higher porosity of 5.6%, compared with 1.2% for carbonate-rich shale, decane was more easily removed from the carbonate-rich matrix, leading to similar hydrocarbon yields. These promising results demonstrate the ability of SANS and USANS to provide key insights into oil recovery from nano- to micron-sized pores in shale matrices. Combined with effects of various fractures on fluid behavior in shale, this experimental technique can be used to assess the viability of EOR injectants.

Application of IOR techniques in fractured basement reservoirs – A case study

As the production of oil and gas from conventional reservoirs is declining steadily, the interest in development of naturally fractured basement reservoirs has been on the rise in the past few decades. The naturally fractured reservoirs category comprises basement reservoirs which in turn includecrystalline formations ranging from intrusive and extrusive magmatic bodies (particularly granites) to the low to medium-grade metamorphic rocks. Basement refers to a set of igneous (intrusive or extrusive) and metamorphic rocks that sit under an unconformity at the bottom of a sedimentary sequence. In crystalline fractured and weathered crystalline basement reservoirs, natural fractures play an important role in hydrocarbon migration and storage. Naturally fractured reservoirs account for a huge share of the world's remaining hydrocarbon reserves. The hydrocarbon industry has known for a long time that naturally fractured basement reserves exist. They were once thought to be non-productive and were frequently labelled as having “no economic potential.” They may, however, be found in a wide range of petroliferous basins all over the world. Many IOR techniques are used and studied in this technical paper for developing a favourable model for improved hydrocarbon recovery from naturally fractured reservoirs, including hydraulic proppant fracturing, advanced emulsion acidizing stimulation, directional drilling application, gel treatment, and other favourable IOR techniques.

A Novel Energy Lifting Approach Using J-Function and Flow Zone Indicator for Oil Fields

The X field is located in the southwestern part of block NX89 of Kentan Basin in Libya. This field is produced from Hailan multilayer consolidated sandstone with moderate rock property and a relatively low energy supplying. The reserve of subsurface energy sources is declining with years. Therefore, techniques were combined to achieve the energy optimization and increase hydrocarbon recovery. In order to understand the subsurface formation of the reservoir and facilitate oil production, global hydraulic element technique was used to quantify the reservoir rock types. In addition, stratigraphic modified Lorenz plot was used for reservoir layering. Reservoir heterogeneity was identified using stratigraphic modified Lorenz plot and Dykstra-Parsons coefficient. Leverett J-function was used to average the 13 capillary pressure curves into four main curves to represent the whole reservoir based on flow zone indicator values. Capillary pressure was calculated and plotted with normalized water saturation; a single average curve was defined to represent the rest of the curves. Water saturation was calculated using single and multiple J-functions and compared with the available logs. With multiple J-functions, the matching results were good for both high and low-quality layers, whereas using a single J-function, the match was poor, especially for low FZI layers such as H4c and H6a. Four rock types were identified for this reservoir ranging from medium to good reservoir quality and six different layers were obtained. The reservoir was heterogeneous with a Lorenz coefficient value of approximately 0.72 and a Dykstra-Parsons value of 0.70. All approaches used in this paper were validated and showed improved hydrocarbon recovery factor.

Polymeric surfactants for enhanced oil recovery: A review of recent progress

Chemical enhanced oil recovery (CEOR) is a well-recognized technique for exploiting the original oil in place (OOIP) left behind in subsurface petroleum reservoirs after primary and secondary recovery processes. However, CEOR is not practiced or implemented widely because of project cost, operational and technical complexity, and environmental risks. Polymeric surfactants have emerged as a viable alternative to conventional chemical methods. They offer multifunctional mechanisms such as viscosity increment and interfacial tension (IFT) reduction. Thus, they are thought to be more versatile in enhancing recovery due to mobility control and wettability-induced fluid redistribution. This review presents a summary of recent studies in the literature that provides new insights into the properties, mechanisms, and applications of polymeric surfactants related to improved hydrocarbon recovery. From the published studies, fluid-fluid interactions influencing rheology and IFT, and fluid-rock interactions dictating wettability alteration and adsorption tendencies, are systematically evaluated. Implications of these mechanisms on enhanced hydrocarbon recovery by the polymeric surfactants are analyzed. Recent advances and knowledge gaps are highlighted, and possible directions to improve research methodology are suggested. • Most polymeric surfactants exhibit more remarkable rheological and emulsifying properties than conventional polymers. • The superior tolerances to harsh external conditions by polymeric surfactants are derived from associating properties. • The principal mechanisms of recovery during polymeric surfactant flooding is not yet explicit. • Polymeric surfactants change the wetting properties of rock surfaces mainly via adsorption mechanisms. • Polymeric surfactants of slightly lower weight have better mobility control and recovery potentials than conventional polymers.

An Empirical Analog Benchmarking Workflow to Improve Hydrocarbon Recovery

Summary Benchmarking the recovery factor and production performance of a given reservoir against applicable analogs is a key step in field development optimization and a prerequisite in understanding the necessary actions required to improve hydrocarbon recovery. Existing benchmarking methods are principally structured to solve specific problems in individual situations and, consequently, are difficult to apply widely and consistently. This study presents an alternative empirical analog benchmarking workflow that is based upon systematic analysis of more than 1,600 reservoirs from around the world. This workflow is designed for effective, practical, and repeatable application of analog analysis to all reservoir types, development scenarios, and production challenges. It comprises five key steps: (1) definition of problems and objectives; (2) parameterization of the target reservoir; (3) quantification of resource potential; (4) assessment of production performance; and (5) identification of best practices and lessons learned. Problems of differing nature and for different objectives require different sets of analogs. This workflow advocates starting with a broad set of parameters to find a wide range of analogs for quantification of resource potential, followed by a narrowly defined set of parameters to find relevant analogs for assessment of production performance. During subsequent analysis of the chosen analogs, the focus is on isolating specific critical issues and identifying a smaller number of applicable analogs that more closely match the target reservoir with the aim to document both best practices and lessons learned. This workflow aims to inform decisions by identifying the best-in-class performers and examining in detail what differentiates them. It has been successfully applied to improve hydrocarbon recovery for carbonate, clastic, and basement reservoirs globally. The case studies provided herein demonstrate that this workflow has real-world utility in the identification of upside recovery potential and specific actions that can be taken to optimize production and recovery.