Increase Oil Production Research Articles

Limited increases in Arctic offshore oil and gas production with climate change and the implications for energy markets

Climate change impacts on sea ice thickness is opening access to offshore Arctic resources. The degree to which these resources are exploited will depend on sea-ice conditions, technology costs, international energy markets, and the regulatory environment. We use an integrated human-Earth system model, GCAM, to explore the effects of spatial–temporal patterns of sea-ice loss under climate change on future Arctic offshore oil and gas extraction, considering interactions with global energy markets and emission reduction scenarios. We find that under SSP5, a “fossil-fueled development” scenario, the effects of sea-ice loss are larger for Arctic offshore oil production than gas. Under SSP5, future extraction of Arctic offshore oil and gas through 2100 adds roughly 0.8–2.6 EJ/year to oil and gas markets but does not have large impacts on global oil and gas markets. Surprisingly, a low-carbon scenario results in greater Arctic offshore oil production to offset the more emissions-intensive unconventional oil production.

Impact of skin sensitivity mechanisms on sebum secretion: Management strategies for oily sensitive skin

Recent epidemiological surveys based on Baumann's classification have revealed a notable rise in the prevalence of oily sensitive skin. The development of oily sensitive skin is primarily linked to the abnormal function of sebaceous glands. The function of sebaceous glands is regulated by several factors, including inflammatory mediators, neurotransmitters, and endocrine signals. Sensitive skin, particularly oily sensitive skin, is prone to local inflammation, which in turn disrupts the normal functioning of sebaceous glands. This creates a loop wherein increased oil production exacerbates sensitivity, while heightened sensitivity further stimulates sebum secretion, perpetuating a vicious cycle. This article summarizes our understanding of the four primary mechanisms underlying skin sensitivity and their impact on sebaceous gland activity. Accordingly, it proposes management strategies for oily sensitive skin and seeks to guide the development of skin care regimens for this skin type.

Using ANN for well type identifying and increasing production from Sa’di formation of Halfaya oil field – Iraq

Abstract The current study focuses on utilizing artificial intelligence (AI) techniques to identify the optimal locations of production wells and types for achieving the production company’s primary objective, which is to increase oil production from the Sa’di carbonate reservoir of the Halfaya oil field in southeast Iraq, with the determination of the optimal scenario of various designs for production wells, which include vertical, horizontal, multi-horizontal, and fishbone lateral wells, for all reservoir production layers. Artificial neural network tool was used to identify the optimal locations for obtaining the highest production from the reservoir layers and the optimal well type. For layer SB1, the average daily production is 291.544 STB/D with the horizontal well, 441.82 STB/D with the multilateral well, and 1298.461 STB/D with the fishbone well type. Also, for the SB2 layer: 197.966, 336.9834, and 924.554 STB/D, and for the SB3 layer: 333.641, 546.6364, and 1187.159 STB/D for the same well type sequence. The cumulative production for each formation layer is 22.440 MMSTB from the horizontal well, 59.05 MMSTB from the multilateral well, and 84.895 MMSTB from the fishbone well types for the SB1 layer; 48.06, 70.1094, and 160.254 MMSTB for SB2; and 75.2764, 111.7325, and 213.1291 MMSTB for SB3 for the same well types.

Study on Micro-Pressure Drive in the KKM Low-Permeability Reservoir

Kazakhstan has abundant resources of low-permeability oil reservoirs, among which the KKM low-permeability oil reservoir has geological reserves of 3844 × 104 t and a determined recoverable reserve of 1670 × 104 t. However, the water flooding efficiency is only 68%, and the recovery efficiency is as low as 32%. The development of the reservoir faces challenges such as water injection difficulties and low oil production from wells. In order to further improve the oil recovery rate of this reservoir, our team developed micro-pressure-driven development technology based on pressure-driven techniques by integrating theories of fluid mechanics and artificial intelligence. We also combined this with subsequent artificial lift schemes, resulting in a complete set of micro-pressure-driven process technology. The predicted results indicate that after implementing micro-pressure-driven techniques, a single well group in the KKM oilfield can achieve a daily oil production increase of 32.08 t, demonstrating a good development effect.

Nodal Analysis of Naturally Flowing Wells in Faihaa Oil Field, Yamama Formation

This study focuses on the Yamama Formation, a significant carbonate reservoir in southern Iraq that is one of the most important productive reservoirs in the region. The Formation is characterized by porous limestone interspersed with thin layers of argillaceous and tight limestone. The Yamama reservoir in the Faihaa oil field is divided mainly into four units; YA, YB, YC, and YD. YA and YB units are considered to be the most important oil-bearing subunits due to their good petrophysical properties. The main objective of the study is to determine the optimum production rates of four naturally flowing wells in the Faihaa oil field using the Inflow Performance Relationship and Vertical Lifting Performance curves. The study investigates four critical parameters; tubing size, water cut, reservoir pressure, and wellhead pressure, and their impact on well performance. The study finds that wellhead pressure is the primary determinant of well performance, and deviations from the original tubing size have adverse effects on well performance. An increase in water cut beyond the recommended threshold, coupled with a reduction in reservoir pressure, results in decreasing well performance. The study underscores the importance of careful monitoring and analysis of these parameters to sustain and enhance well performance in the Faihaa oil field, providing valuable insights for well operators and petroleum engineers. The study's findings can be used to optimize well performance and increase oil production rates, with significant implications for the petroleum industry.

Bio‐enhanced oil recovery (BEOR) methods: All‐important review of the occasions and challenges

AbstractBio‐enhanced oil recovery (BEOR) is an advanced and innovative approach in the oil industry that could be a potential solution to increase oil production from existing reservoirs using technologies based on biological methods. Nevertheless, there has been a lack of comprehensive reviews that elucidate the various aspects and potential of different BEOR methods and processes. This review summarizes the recent progress of various methods employed in BEOR, exploring their applications and highlighting their distinct advantages. BEOR employs different techniques, including microorganisms and biomicrobes microbial enhanced oil recovery (MEOR), enzymes, biopolymers, bionanomaterials, alkaline, and biosurfactants to increase oil recovery. Microorganisms contribute significantly to BEOR through metabolic processes that result in the production of gases and acids. The role of enzymes is to enhance the fluid flow and thereby facilitate oil production. Biosurfactants reduce the interfacial tension (IFT) between oil and water and mobilize the trapped oil. Biopolymers are obtained from biological sources such as plants, microorganisms, and algae. Biopolymers can interact with oil, which is well‐used in the process of EOR. Bionano processes represent a fusion of biology and nanotechnology, integrate the advantages of both microorganisms and nanoparticles, and provide a synergic effect for EOR. The BEOR revealed an attractive potential to be an effective approach to maximizing the oil recovery considering environmental, economic productivity, and sustainability issues. Also, this review encourages further studies and development in this field for fully exploiting BEOR's capacity and meeting the ever‐increasing needs of energy resources with a sustainable viewpoint.

Experimental investigating of the effect of CO2 injection parameters on asphaltene precipitation and formation damage in live oil

AbstractWith the increasing consumption of oil in the world and increasing production of oil from oil reservoirs, the reservoir pressure starts to decrease. On the other side, the use of oil leads to an increase in carbon dioxide production in the environment and causes global warming.One of the effective methods of reducing the amount of carbon dioxide emitted into the atmosphere and increasing the reservoir's pressure is CO2‐EOR and carbon capturing and storing (CCS) which injects produced carbon dioxide from industrial sources into underground reservoirs. Carbon dioxide reduces oil viscosity and increases oil mobility producing an economical state. Moreover, with CO2‐EOR and CCS carbon dioxide can be stored in a depleted reservoir and helps reduce pollution and global warming.Besides the environmental and economic benefits due to reducing carbon dioxide emissions to the atmosphere and increasing oil production, CO2 injection causes various problems in the formation. Many experiments indicate that asphaltene precipitation and wettability alteration caused by asphaltene, dissolution/precipitation of rock, salt precipitation, and sludge formation are some of the problems that occur during CO2 injection operations in low pressure and temperature. However, few experiments evaluate asphaltene precipitation effective factors, such as pressure, injection rates, temperature, etc., in high temperatures and pressure (HPHT) near reservoir conditions. Therefore, there was a need for a comprehensive investigation of various factors and the impact of each of them on the asphaltene precipitation and formation damage in HPHT conditions, so this research was designed to help future simulation and industrial utilization.A core‐flood setup was prepared to conduct CO2 flooding experiments and formation damage studies in HPHT conditions. The main objective of this study was to evaluate the effect of different parameters including pressure, injection rate, and type of injected gas on asphaltene and its effect on formation damage caused by CO2 injection. The second goal of this study was to investigate the optimum injection in every section. The third goal was to determine the oil recovery during the process of CO2 injection in different conditions.The results showed that an injection rate of 0.1 cc/min and higher injection pressures minimized asphaltene precipitation and maximized oil recovery. Replacing CO2 with natural gas liquids (NGL) gas reduced oil production and asphaltene precipitation. Overall, the experiments demonstrated the importance of optimizing injection parameters to limit formation damage during CO2 flooding. © 2024 The Authors. Greenhouse Gases: Science and Technology published by Society of Chemical Industry and John Wiley & Sons Ltd.

Chevron Applies Some Unconventional Thinking To Try To Make Shale EOR a Standard Treatment

In the shale business, the closest thing now to enhanced oil recovery (EOR) is improved techniques. During an earnings call last November an analyst asked EOG Resources executives about their enhanced completion technique which EOG reported was adding 20% to first-year well production in the Permian. Improved completions have allowed operators to significantly increase early production year after year, but after that, steep declines are a given. Back in 2016, EOG was talking about how it was increasing oil production significantly by injecting millions of cubic feet of gas a day into wells in the Eagle Ford. It triggered an EOR field-testing boom by competitors hoping to match reported reserve increases of “30 to 70%.” In a 2017 JPT story, Deepak Devegowda, a petroleum engineering professor at the University of Oklahoma, said, “This is the name of the game. Everybody is talking about EOR and pumping money into trials of EOR.” Now the only mention of the acronym EOR on EOG’s website is an item in its corporate history timeline for 2016: “We commercialized the first enhanced oil recovery process, or EOR, in shale.” In recent years, reported shale EOR work has been mostly in the form of occasional papers describing production uplift by companies selling ways to increase production by injecting gas or chemicals. EOR effectiveness isn’t the issue, according to Todd Hoffman, a petroleum engineering professor at Montana Tech University who wrote two papers evaluating EOG’s methods cited in two Chevron papers. “The EOG field work showed us that these projects can produce significant additional oil and be economically positive,” he said. The problem is that drilling and fracturing wells delivers “higher economic returns than the EOG-style EOR projects with the huge compressors, high gas rates, and high injection pressures.” Last year in the middle of this EOR drought, Chevron did something different. It delivered two papers revealing a major company-scale effort to find ways to use chemical and gas injections to economically produce more oil. The papers presented at the 2023 Unconventional Resources Technology Conference (URTeC) reported on field tests of surfactants and natural gas injection on Permian Basin wells which delivered sufficiently encouraging results to justify an expanded testing program. (URTeC 3870505 and URTeC 3871386). Chevron described a systematic effort by its corporate technical unit and its Mid-Continent business unit to rethink shale EOR methods based on the unconventional nature of flow through fractured reservoirs and the economic realities in a business where new EOR technology is competing with the profitable status quo. Its methods challenge accepted notions about the role of EOR. In SPE’s disciplines, EOR normally falls under the production topic, “marginal aging fields.” What Chevron tested is better described by the topic, “well interventions.” Rather than looking at these techniques as a way to eke out the last barrels from old wells, the papers describe methods that can be deployed earlier in the life of these short-lived wells.

An Application of Polymer Nanocomposites Based On Carboxymethylcellulose along with Aluminium (Al) and Copper (Cu) Nanoparticles for Increasing Oil Production

As an agent for displacing residual and hard-to-recover oil reserves, polymer nanocomposites based on sodium salts of carboxymethylcellulose (CMC) and aluminium (Al) and copper (Cu) nanoparticles were investigated. It has been shown that polymer nanocomposites are more effective as oil displacement agents than the sodium salt of carboxymethylcellulose itself. Increasing the viscosity of an oil displacement solution can be achieved by varying the concentrations of CMC and nanoparticles. This study thoroughly examined the dynamic viscosities of carboxymethylcellulose (CMC) and polymer nanocomposites that contain CMC and metal nanoparticles (Al and Cu) across various concentrations. The results obtained are robust and reliable. It has been shown that, among polymer nanocomposites containing Al nanoparticles, there is a higher dynamic viscosity compared to its Cu nanoparticle counterpart at equivalent concentrations. This work proposes a simulation reservoir model to enhance oil recovery from hard-to-recovery reserves. Through this reservoir model simulation, the oil recovery factor was calculated using filler sand and oil extracted from a hydrocarbon field. The experimental data revealed the most effective concentration of CMC and nanoparticles for oil displacement. The results suggest that polymer nano composites composed of different metal nano powders have varying impacts on oil displacement efficiency. In this experiment, a composition consisting of Al nanoparticles with a size range of 50-70 manometers (nm) proved to be more successful as an oil displacement agent than a polymer nanocomposite made of Cu nanoparticles and CMC. At these concentrations and combinations, the highest oil recovery factors were achieved.

Investigation of the potential of application Frac-Pack technology as a solution to the problem of sand control and increasing the production of high-viscosity oils at M field

Background: In this paper, the potential of applying hydraulic fracturing with the installation of a gravel pack in the Cretaceous horizons of the M field is investigated. The relevance of the work is due to the fact that today the selection of optimal technologies to increase the rate of oil production from the Cretaceous deposits an open platform for proposals and discussions. The low oil recovery coefficient is due to the existing restrictions on the oil production process: high oil viscosity, the presence of gas and water-oil zones, abundant sand production in a poorly cemented reservoir.
 Aim: The purpose of the work is to study the potential application of Frac-Pack technology in the wells of the M field.
 Materials and methods: In order to assess the potential of using Frac-Pack in a special FracPro software, a model of geomechanical and filtration properties of the formation was developed and a simulation of the design with various injection parameters was performed. Based on the results of laboratory studies of the content of mechanical impurities in liquids sampled at the M field, the diameter of the proppant and the flow section of the filter were determined.
 Results: As a result of the study, hydraulic fracturing was simulated for a well from a sample of potential candidates, the oil flow rate was calculated after the application of the proposed technology, materials for the implementation of Frac-Pack technology were selected based on laboratory studies.
 Conclusion: The study showed that the proposed pre-development strategy is the most optimal for shallow wells of the M field, as it is aimed not only at solving the problem of combating the removal of mechanical impurities, but also increasing oil production.

In-situ solvents generation enhanced steam assisted gravity drainage (ISSG-SAGD): A low carbon and high-efficiency approach for heavy oil recovery

The primary bottleneck in heavy oil production lies in the significant energy consumption and CO2 emissions associated with steam injection for recovery. To address this challenge, we propose the ISSG-SAGD (in-situ solvent generation enhanced steam assisted gravity drainage) technique. The recovery mechanisms and operational strategies are investigated using a numerical simulation with an Athabasca bitumen reservoir model, affirming the considerable environmental and economic potential of ISSG-SAGD. The results demonstrate that ISSG-SAGD integrates the recovery mechanisms of both SAGP (steam and gas push) and ES-SAGD (expanding solvent SAGD). Moreover, employing cyclic steam injection, maintaining low operating pressure, and initiating ISSG-SAGD at an early stage enable a 33.79 % reduction in steam consumption, a 39 % decrease in average carbon intensity, a 5.40 % increase in oil production, and a 61.28 % rise in net present value compared to conventional SAGD. This study proves that the ISSG-SAGD approach offers a sustainable and efficient alternative for future heavy oil recovery endeavors, addresses the challenges of high energy consumption and carbon emissions, and paves the way towards a green and economically viable future for the heavy oil development.

Numerical simulation of CO2-enhanced oil recovery in fractured shale reservoirs using discontinuous and continuous Galerkin finite element methods

Introduction: This study explores the potential of enhancing shale oil recovery and reducing CO2 emissions through CO2 injection in fractured shale reservoirs. The importance of this approach lies in its dual benefit: improving oil extraction efficiency and addressing environmental concerns associated with CO2 emissions.Method: We employed a discrete fracture-matrix model to simulate CO2 flooding in fractured shale reservoirs, utilizing both discontinuous Galerkin (DG) and continuous Galerkin (CG) finite element methods. The DG-CG FEM’s accuracy was validated against the McWhorter problem, ensuring the reliability of the simulation results. Our model also considered various factors, including reservoir heterogeneity, fracture permeability, CO2 injection volume, and gas injection patterns, to analyze their impact on shale oil recovery.Result: Our simulations revealed that fractured reservoirs significantly enhance shale oil production efficiency compared to homogeneous reservoirs, with an approximate 48.9% increase in production. A notable increase in shale oil production, by 15.8%, was observed when fracture permeability was increased by two orders of magnitude. Additionally, a fourfold increase in CO2 injection rate resulted in a 31.5% rise in shale oil production. Implementing a step-by-step reduction in injection volume while maintaining the total CO2 injection constant proved to be more effective than constant-rate injections.Discussion: The study demonstrates the effectiveness of CO2 flooding in fractured shale reservoirs for enhancing shale oil recovery.

Comparative Assessment of Conventionally and Locally Sourced Surfactants for Enhancing Steam Flooding Techniques for Heavy Oil Recovery in Niger Delta

The recovery of heavy oil reserves presents a significant challenge in the petroleum industry due to its high viscosity and poor mobility characteristics. Steam flooding, as a thermal Enhanced Oil Recovery (EOR) technique, has shown promise in mobilizing heavy oil deposits. However, the limited success of conventional steam flooding in heavy oil reservoirs necessitates innovative approaches. This study explores the utilization of conventional and locally sourced surfactants in surfactant-enhanced steam flooding (SESF) for heavy oil recovery in the Niger Delta region. The study examines the selection, formulation, and injection of surfactants specifically tailored for heavy oil reservoir conditions. Laboratory experiments, core flooding tests, and numerical simulations are conducted to evaluate the impact of surfactants on interfacial tension reduction, wettability alteration, and improved oil mobility in heavy oil reservoirs subjected to steam flooding. The project’s findings demonstrate the significant potential of (SESF) for heavy oil recovery. The synergistic effects of surfactants and steam, including the reduction of oil-water interfacial tension, lead to increased oil production rates, reduced steam consumption, and enhanced sweep efficiency. Furthermore, economic assessments are conducted to evaluate the feasibility of implementing this approach on a field scale, considering both technical and economic aspects. This study not only contributes valuable insights to the field of heavy oil recovery but also underscores the practicality of surfactant-enhanced steam flooding as an environmentally responsible solution for unlocking the vast heavy oil reserves worldwide. The research bridges the gap between laboratory findings and real-world applications, offering a promising path forward for the sustainable development of heavy oil resources.

Horizontal well placement optimization based on matrix directional continuous element summation algorithm

During the course of actual oilfield development, judicious selection and design of well placement are paramount due to cost constraints and operating conditions. This paper introduces the Matrix Directional Continuous Elements Summation Algorithm (MDCESA), which is utilized to identify that segment with the largest summation for a given length in a 2D or a 3D matrix. An additional function that accounts for the distance between segments was added when searching for multiple segments to avoid intersections or overlaps between segments. The well placement optimization was transformed into a segment summation on a 3D matrix. Our findings reveal significant advancements in well placement optimization. Employing the MDCESA method, six producers were identified and their production performance was compared against two previously selected producers using a reservoir numerical simulator. The results demonstrated that the wells selected through MDCESA exhibited a substantial improvement in production efficiency. Specifically, there was an 11.6% increase in average cumulative oil production over a 15-year period compared to the wells selected by traditional methods. This research not only presents a significant leap in well placement optimization but also sets a foundation for further innovations in reservoir management and development strategies in offshore oilfields.

Efficience of multistage fracturing in horizontal wells of the Kashiro-Podolsk deposits

The article is devoted to the methods of extracting reserves from complex carbonate reservoirs based on a complex of geological and technical measures. The parameters influencing the technological efficiency and the increase in oil production are analyzed. These include geological and filtration-capacitive heterogeneity, as well as technological parameters. The division of carbonate rocks into petrotypes is considered in order to assess their impact on input technological indicators – water content, oil flow rate. Geological conditions have been studied, as well as geological and technical parameters that have a significant impact on oil production and reservoir flooding during the multistage acid fracturing. The studied relationships allow for a detailed analysis of the success of events and a detailed approach to the selection of candidate wells.

Анализ разработки Южно-Осташковичского месторождения нефти

The article presents the results of the development of inter-salt and intra-salt oil deposits of the South-Ostashkovichskoye oil field from the moment of commissioning. The main problem revealed for the field development is a high water cutting of well production that made necessary to systematically carrying out a number of geological and technical measures. The most effective measures used to stabilize and increase oil production are highlighted. In order to meet the established environmental standards during the development of the deposit, proposals for the application of the specific environmental protection measures have been introduced.

Exploring the use of microbial enhanced oil recovery in Kazakhstan: a review.

Microbial enhanced oil recovery (MEOR) is a promising method for improving oil recovery from challenging reservoirs such as those found in Kazakhstan. MEOR relies on the activities of microorganisms to modify the properties of the reservoir, such as reducing the oil viscosity, increasing the reservoir permeability, and generating by-products that mobilize the oil. Implementing MEOR in Kazakhstan could lead to significant economic benefits for the country by increasing oil production and royalties from fossil fuel exports. Oil production in Kazakhstan has seen fluctuations in recent years, with 2018 recording a production level of 1.814 million barrels per day. Among regions, Atyrau region contributed the most to oil production with 23.4 million tons of oil. Following Atyrau, the Mangystau region produced 8.2 million tons, and Aktobe produced 2.4 million tons. Overall, the use of MEOR in Kazakhstan's oil fields could offer a promising solution for enhanced oil recovery, while minimizing environmental impact and cost. While specific data on the current use of MEOR in field conditions in Kazakhstan might be limited, the fact that studies are underway suggests a growing interest in applying this technology in the country's oil fields. It is exciting to think about the potential benefits these studies could bring to Kazakhstan's oil industry once their findings are implemented in field operations. These studies have significant implications for Kazakhstan's oil production in the future.

Construction of middle-phase microemulsion system and its micro-mechanism on displacing residual oil in low-permeability porous media.

The application of medium-phase microemulsion in enhancing oil recovery technology represents a significant area of research, particularly for improving production in low-permeability reservoirs. The oil recovery can be increased to 80%~90%. In order to further improve the recovery rate of low-permeability reservoirs in the late stage of water flooding, a medium-phase microemulsion flooding system was constructed in this paper. The micro-displacement mechanism of the medium-phase microemulsion flooding system was clarified by experimental methods such as phase change and micro-remaining oil distribution. The ability of enhancing oil recovery and the mechanism of increasing oil production were discussed, which provided a basis for establishing a new method of enhancing oil recovery. This study utilizes a mixed surfactant system composed of sodium dodecyl benzene sulfonate and coconut oil fatty acid lipopolyoxyethylene betaine at a mass ratio of 1:3, with n-butanol serving as the cosurfactant. The fish phase diagram was instrumental in determining the critical concentration range for alcohol (1.3%-3.7%) necessary for the formation of middle-phase microemulsions, along with a corresponding surfactant mass concentration of 0.3%-0.7%. Key salinity thresholds for middle-phase formation and disappearance were identified at 1.5% and 6.0%, respectively. Optimal solubilization effects were observed at approximately 4.8% NaCl mass concentration, which effectively reduced interfacial tension to 10-3mN/m. Under specific kinetic conditions, in-situ formation of middle-phase microemulsions occurs as surfactants interact with crude oil within reservoir pores. In comparison to traditional water flooding, middle-phase microemulsions enhance viscosity and create an oil wall at the forefront of displacement. This mechanism facilitates the aggregation and movement of residual oil, which is crucial for enhancing crude oil recovery. Moreover, middle-phase microemulsions exhibit strong solubilization capabilities, making them particularly effective for mobilizing oil in blind-end and unswept areas. The ultra-low interfacial tension achieved between the microemulsion and crude oil promotes the elongation and fragmentation of pore-trapped oil into smaller droplets, ultimately aiding in their displacement and recovery via micro-pore outlets. This unique interaction underscores the potential of middle-phase microemulsion flooding to optimize oil recovery processes, especially in challenging reservoir environments such as those encountered in the Changqing Oilfield formations.

Groundwater Use in Yenagoa: Impact on Residential Development and Investment

In the oil-producing metropolis of Yenagoa and its surroundings in Bayelsa State, Nigeria’s Yenagoa Local Government Area (YELGA), groundwater is the main and only safe source of water. As the capital of Bayelsa State, the city experienced rapid development, resulting in an influx of people and a subsequent freshwater deficit due to increased oil production and groundwater pollution. For the sustainable growth of water resources, preventing water or piezometer level fluctuations and quantitatively estimating the area’s available water supplies are crucial. To meet the water needs of the population, boreholes are dug using rotary technology and cable devices. The size of the borehole, the type of construction, the type of material used (casing and screen), and the availability of sachet water are some of the many factors that affect the cost of constructing a water borehole in Yenagoa and its environs. This study shows that the location of the study area in the riverine Niger Delta area of Nigeria makes the construction of boreholes more expensive. Data on the cost of drilling boreholes in the exhibited area shows a significant increase over time. It is shown that the long economic life of drilled borehole depends on monitoring of aquifers and wells, as well as maintenance of wells, pumps, and accessories, all of which prove inadequate.

Waterflooding optimization based on the CRM and solving the linear programming problem

Among the many technologies for increasing the efficiency of oil field development using waterflooding, the least economically expensive include hydrodynamic methods for increasing oil recovery, based on changing the directions of filtration flows. Thus, one of the key tasks of increasing the efficiency of waterflooding at a late stage of development is to reduce the volume of ineffective injection. The article discusses the problem of redistributing volumes of injected water between injection wells for a given total injection volume in order to increase oil production. An analytical relationship is proposed for assessing injection efficiency, based on known displacement characteristics and calculated well interference coefficients based on CRMP. The optimization problem is formulated as a linear programming problem. Using the example of a fragment of an oil deposit, the possibility of assessing the injectivity of injection wells is shown, which makes it possible to increase the predicted oil production by changing the direction of filtration flows in the formation. As a result of applying the developed algorithm, the predicted increase in cumulative oil production amounted to 19683 m³ (9.5%) over 15 years. Keywords: waterflooding optimization; capacitive-resistive model; CRM; linear programming; injection efficiency; interwell connectivity.