Injection Wells Research Articles

Application of Pulse Neutron Oxygen Activation Logging in Carbon Dioxide Injection Wells

Carbon dioxide injection to improve oil recovery is an important link in carbon capture, utilization, and storage (CCUS) and an important means of tertiary oil recovery. Conducting gas injection profile logging in injection wells can reflect the inter-and intra-layer suction differences in gas injection wells, reveal the contradictions between injection and production, and provide a basis for gas plugging and profile control; The integrity of the wellbore is an important part of the storage stage of CCUS, which directly determines the burial and storage effect, and wellbore leakage directly affects the gas injection and oil displacement effect; The inspiratory index test can evaluate the formation's gas absorption capacity and provide a reasonable injection pressure of the formation at this stage. Since carbon dioxide gas usually exists in a supercritical fluid state in the wellbore, traditional logging techniques have certain limitations. This paper focuses on the adaptability research of pulse neutron oxygen activation logging principle and construction technology, and combined with the application example of gas injection wells in CCUS block of Huang3 District in Changqing Oilfield, it is clarified that the pulse neutron oxygen activation logging can be used to carry out suction profiling, suction index testing and wellbore integrity evaluation in carbon dioxide injection wells, and it has good application effects.

Feasibility Assessment of Acid Gas Injection in an Iranian Offshore Aquifer

Acid gas injection operations function as the commercial equivalent of certain aspects within the realm of geological CO2 storage. Acid gas, composed of H2S and CO2, alongside minor quantities of hydrocarbon gases stemming from either petroleum production or processing, constitute the composition of acid gas. The primary aim of acid gas injection operations lies in the disposal of H2S. Nevertheless, substantial volumes of CO2 are concurrently injected due to the economic impracticality of segregating the two gases. This investigation delves into the comprehensive, step-by-step procedure that can be employed to determine the suitability of a field or formation for acid gas injection, utilizing all accessible data, including the literature and data from neighboring fields. This approach incorporates sensitivity analysis of various parameters to ascertain the feasibility of AGI while minimizing costs and time consumption. The focus of this study centers on evaluating the feasibility of Acid Gas Injection (AGI) in a saline aquifer offshore in Iran. The assessment encompasses the examination of reservoir properties, geomechanical aspects, caprock integrity, and gas plume dynamics. The Surmeh formation emerges as a promising candidate for AGI due to the presence of upper dolomite and lower carbonate within the rock formations. Geomechanical analysis reveals a pore pressure of 3800 psi and a fracture pressure of 6100 psi. Caprock integrity, particularly within the Hith formation, emerges as pivotal for both containment and long-term stability. Seismic mapping highlights variations in caprock thickness, influencing containment effectiveness. Capillary trapping emerges as a significant factor in short-term gas entrapment and plume distribution. Numerical simulations elucidate the impact of heterogeneous rock properties on capillary trapping and gas plume movement. The projection estimates approximately 2 TCF (Trillion Cubic Feet) of acid gas injection into the Surmeh formation. Based on the acid gas content and the gas in place at the source of injection, the recommended injection rate stands at 180 MMSCFD (million standard cubic feet per day). The formation’s inherent tightness limits injectivity, allowing for a maximum achievable rate of 7 MMSCFD with a permeability of 1 mD (millidarcy). However, a higher porosity (12%) and a permeability of 100 mD enable more efficient injection without fracturing the formation. To achieve this, it becomes imperative to implement two injection wells, each with a capacity of 90 MMSCFD.

Fracture conductivity management to improve heat extraction in enhanced geothermal systems

The efficiency of an enhanced geothermal reservoir (EGS) depends on the effective circulation of the working fluid through the geothermal formation. To remove the thermal shortcut that leads to thermal short-circuiting in the EGS, we present a method of fracture hydraulic conductivity management and present some practical ways to implement it in the field. The core idea is to correlate the flow resistance in different flow channels with temperature, in order to make uniform heat extraction through each flow path. The presented technique is an adaptive and reversible system and is trying to engineer the fracture system for effective delay of the early thermal breakthrough in EGS. Results indicate that the proposed fracture conductivity tuning technique (FCTT) can help to avoid flow and thermal shortcuts between the wells and maintain high heat extraction rates. The autonomous management of fracture conductivity may increase cumulative heat extraction by more than 214 %, and reduce an extra 1.06 – 3.65 Mt of greenhouse gas emission through electricity generation after 50 years of EGS development, which is highly considerable for EGS development. Besides, we found that it could be still beneficial to apply such methods solely to the injection wells, which can also bring a heat extraction improvement of 201.9 %. Furthermore, we look at the situations when the special conductivity tuning agents are placed in the middle between the wells, it is still very effective to control the fluid flow in the reservoir and enhance heat extraction. By proposing the tunable fracture conductivity, we are trying to revisit the old problem of thermal short-circuiting and provide new insight into the efficient EGS operation.

Analysis of Cement Sheath–Rock Damage Mechanism—A Case Study on Water Injection Wells

In the field of water injection wells within oilfields, comprehending the intricate mechanics of water channeling and the resulting rock damage on the external cemented surface holds paramount significance for the efficient management of reservoirs. This paper presents a comprehensive study aimed at illuminating the complex nature of rock damage on the external cemented surface of casings and deciphering the underlying mechanisms that underpin water channeling occurrences. To this end, a robust constitutive model is established and refined to capture the multifaceted interactions inherent in rock damage on the cemented surface. This model introduces a modified bonding force approach to enhance shear stress precision and thoughtfully accounts for the profound effects of elastic–plastic behavior, cracking damage, and elastic-cracking coupling damage on damage progression. Subsequently, the refined model is employed to investigate rock damage on the external cemented surface of water injection wells, encompassing variations in confining pressure, rock width on the cemented surface, and the ratio of Young’s modulus between the cement sheath and the rock. The research findings emphasize the interplay between cracking and elastic damage as the catalyst for rock damage on the cemented surface. Impressively, the accuracy of the refined constitutive model for the cemented surface has advanced by over 5% compared to prior studies. The manipulation of confining pressure and the Young’s modulus ratio enhances peak fracture water pressure, signifying substantive strides in comprehending damage propagation mechanics. Furthermore, the study discerns the negligible influence of rock width on the cemented surface regarding damage patterns. These findings have important implications for the effective management of water injection wells, providing insights for the restoration of water channeling wells and proactive measures against water channeling phenomena. They also contribute to the refinement of well cementing practices and the proficient management of water channeling and water flooding in oilfields. The research findings have profound implications for the domain of water injection wells, offering novel insights into the restoration of water channeling wells and the implementation of preemptive measures against water channeling phenomena. These findings hold the potential to guide the refinement of well cementing practices and the adept management of water channeling and water flooding wells within the studied oilfield.

Iron corrosion concomitant with nitrate reduction by Iodidimonas nitroreducens sp. nov. isolated from iodide-rich brine associated with natural gas.

Microbially influenced corrosion (MIC) may contribute significantly to corrosion-related failures in injection wells and iron pipes of iodine production facilities. In this study, the iron (Fe0) corroding activity of strain Q-1 isolated from iodide-rich brine in Japan and two Iodidimonas strains phylogenetically related to strain Q-1 were investigated under various culture conditions. Under aerobic conditions, the Fe0 foil in the culture of strain Q-1 was oxidized in the presence of nitrate and yeast extract, while those of two Iodidimonas strains were not. The amount of oxidized iron in this culture was six times higher than in the aseptic control. Oxidation of Fe0 in aerobic cultures of nitrate-reducing bacterium Q-1 was dependent on the formation of nitrite from nitrate. This Fe0 corrosion by nitrate-reducing bacterium Q-1 started after initial nitrite accumulation by day 4. Nitrate reduction in strain Q-1 is a unique feature that distinguishes it from two known species of Iodidimonas. Nitrite accumulation was supported by the encoding of genes for nitrate reductase and the missing of genes for nitrite reduction to ammonia or nitrogen gas in its genome sequence. Phylogenetic position of strain Q-1 based on the 16S rRNA gene sequence was with less than 96.1% sequence similarity to two known Iodidimonas species, and digital DNA-DNA hybridization (dDDH) values of 17.2-19.3%, and average nucleotide identity (ANI) values of 73.4-73.7% distinguished strain Q-1 from two known species. In addition of nitrate reduction, the ability to hydrolyze aesculin and gelatin hydrolysis and cellular fatty acid profiles also distinguished strain Q-1 from two known species. Consequently, a new species, named Iodidimonas nitroreducens sp. nov., is proposed for the nitrate-reducing bacterium strain Q-1T.

Estimation of Temperature Profiles using Low-Frequency Distributed Acoustic Sensing from In-Well Measurements

Summary Distributed fiber-optic sensing for in-well measurements is primarily used for monitoring purposes. Distributed acoustic sensing (DAS) is used to record acoustic disturbances and is sensitive to changes in strain, pressure, and temperature. Distributed temperature sensing (DTS) is used to measure temperature along the fiber. Here, we compare temperature changes measured by DAS and DTS in wells over different time periods. We affirm the linear dependency between DAS’s phase change and temperature, with the derived strain rate being proportional to the time derivative of the temperature response. Given that low-frequency (LF) DAS is sensitive to strain, pressure, and temperature effects, one must choose quiet periods in the well or condition the data to only analyze the effect of temperature on the fiber. We show that LF-DAS data can be used to track temperature changes over several weeks. We then propose a method, using liquid column movements, to invert LF-DAS data for absolute temperature profiles. The temperature profile in a well can be measured using DTS. However, DTS data are not always available, and conventional Raman scattering DTS is not used in subsea wells with long lead-in lengths. Hence, it would be desirable to acquire the temperature response from LF-DAS data to use as a multipurpose tool for in-well monitoring. Here, we show that when purely investigating the response to an initial displacement of the fluid column (i.e., from rest), LF-DAS can be used along with reference sensors, such as the wellhead and downhole temperature gauge data to estimate the depth variations in temperature in production and injection wells.

Superficial versus deep parasternal intercostal plane blocks: cadaveric evaluation of injectate spread

BackgroundDeep and superficial parasternal intercostal plane blocks provide anterior chest wall analgesia for both breast and cardiac surgery. Our primary objective of this cadaveric study was to describe the parasternal spread of deep and superficial parasternal intercostal plane blocks. Our secondary objectives were to describe needle proximity to the internal mammary artery when performing deep parasternal intercostal plane blocks, and compare lateral injectate spread and extension into the rectus sheath. MethodsWe performed ultrasound-guided deep and superficial parasternal intercostal plane blocks 2 cm from the sternum at the T3–4 interspace in four fresh frozen cadavers as described in clinical studies. ResultsParasternal spread of injectate was greater with the deep parasternal intercostal plane injection than with the superficial parasternal intercostal plane injection. The internal mammary artery was ∼3 mm away from the needle trajectory in cadaver #1 and ∼5 mm from the internal mammary artery in cadaver #2. Lateral spread extended to the midclavicular line for all deep parasternal intercostal plane blocks and beyond the midclavicular line for all superficial parasternal intercostal plane blocks. Neither block extended to the rectus sheath. ConclusionsA greater number of parasternal interspaces were covered with the deep parasternal intercostal plane block than with the superficial parasternal intercostal plane block when one injection was performed at the T3–4 interspace. However, considering proximity to the internal mammary artery, and potential devastating consequences of an arterial injury, we propose that the deep parasternal intercostal plane block be classified as an advanced block and that future studies focus on optimising superficial parasternal intercostal plane parasternal spread.

Company Fair Valuation Considering Esg Factor (Case Study: Pt Pertamina Geothermal Energy, Tbk)

The increments of environmental, social, and governance-based investments have been seen recently by institutions or retail investors. The growth has increased rapidly since 2012. Some research gives a positive correlation between the ESG factor represented by ESG rating and company performance. PT Pertamina Geothermal Energy, Tbk. (PGEO), IPO on 24th February 2023 has outstanding ESG performance. It was audited by Sustainable Fitch and got the highest second rank, 77 out of 100 points. Not only is it exceptional ESG performance, but it also has excellent business performance. PGEO started its journey of geothermal utilization in 1974, upon discovering 70 geothermal areas in Indonesia as a sub-business of PT Pertamina EP. PGEO was established in 2006 to continue the efforts to produce clean and environmentally friendly energy, and as of now, it has contributed 82% of the installed geothermal energy capacity in Indonesia. It has the world’s most extensive geothermal installed capacity by December 2021 and promises to expand even more significantly in its prospectus. Investors should consider their value rather than positive sentiment as an investment decision. Then, this study determines whether the PGEO price is undervalued or overvalued considering their project expansion and ESG factor. This study utilizes secondary data from prospectuses, financial statements, annual reports, sustainability reports, company-published documents, and data from IDX.co.id and stockbit.com. The data was gathered and processed to understand the need to expand, analyze its financial performance, and value the company. The author considers company ESG performance to develop financial projections. To fulfill company promises in expansion and stay sustained by adding more production, injection, and startup wells, it needs 1.588.612.527 USD using ESG-based financing. The historical financial performance of PGEO is quite good, but the investor should be careful about its liquidity since the current liability is more significant than its current asset. Based on the calculation of absolute valuation using discounted cash flow, the value of each share of PGEO is Rp12.686,00, which is undervalued, and its IPO price is Rp875,00. Based on relative valuation using PER to its peers and average industry, PGEO’s price is overvalued. The PGEO price that pars with the industry average is Rp490,00. The author can determine the fundamental value of PGEO.

RESULTS OF RESEARCH OF CHEMICAL METHODS TO IMPROVE THE EFFICIENCY OF WATERTREATMENT FOR INJECTION INTO THE SYSTEM OF RESERVOIR PRESSURE MAINTENANCE

The separated water from Preliminary Water Removal Unit isused as a working agent of the pressure maintenance system and, accordingly,the quality must meet regulatory requirements. Pumping waterinto the reservoir without preliminary preparation and considering thephysicochemical properties of water and porosity of the reservoir leadsto contamination of the bottom-hole zone of the well and to reducing theintake capacity of injection wells. Recovery of injection well performancerequires a lot of material and energy costs.The use of gravity sedimentation and oil sedimentation tanks make itpossible to obtain water with a content of petroleum products up to30-50 mg/l and mechanical impurities of 20–40 mg/l. The standardapproach to solving the problems of increasing loads and destruction ofstable oil-water emulsions is increasing the capacity of the treatmentfacility by building additional reservoir equipment. This approachinvolves a number of significant time and financial costs and does notallow to organize a solution to the problem in a short time.The influence of deoilers to the quality of water treatment has been studiedin order to provide deeper purification of reservoir water for thepossibility of obtaining water containing petroleum products andmechanical impurities up to the requirements of the OST-39-225-88.Deoilers do not dissolve or remove petroleum products. Deoilers enlargepetroleum productsby bringing them closer to each other. Then mechanicalimpurities and petroleum products must be removed from the existingwater treatment system. The research of the influence of deoilers forthe stabilization of the oil-water emulsion has been carried out.According to the results of studies of the effect of deoilers on the qualityof water treatment, with the use of all tested deoilers, the content ofpetroleum products in the water decreases and it is possible to obtainwater of the quality required by OST-39-225 under the conditions of oiland water treatment during the technological mode of operation of theUPS. At the same time, however, the supply of trapped oil to the pipelinein front of the oil sedimentation tanks leads to an increase in the residualwater in the treated oil. To minimize the risks of disruption of thetechnological regime at the UPS, the recommended ratio of incomingliquid — captured oil when using deoilers for water purification wasdetermined.

ANALYSIS OF HYDRODYNAMIC INTERACTION OF WELLS BASED ON DETERMINATION OF PRODUCTION AND INJECTION COMPENSATION BALANCE USING THE EXAMPLE OF RESERVOIR — BARREM CLINOFORM OF PRIOBSKY SEDIMENTATION BASIN

Abstract. Long-term development of oil fields using a reservoirpressure maintenance system by injecting water into the formation leadsto a number of features of well operation identified during fieldgeophysical and hydrodynamic studies. The combination and processingof parameters characterizing the field development indicators and theoperation of wells in the injection-production section make it possible toconduct a qualitative assessment of the processes occurring in the subsoil.The article describes the procedure for determining possible sources ofwater flooding of oil wells in a large multi-zone field in Western Siberia.In order to determine the compensatory balance of production andinjection taking into account the regional stress characteristic of the field,calculations were made using a geometric figure in the form of an ellipse.The drainage zone described in this way does not contradict the ratio ofthe number of injection and oil wells in the nine-point developmentsystem. The analysis of geological and field information and hydrodynamicstudies made it possible to identify a difference in the signs of increasedwater cut of the product with uncontrolled growth of a man-made fracturein the direction of regional stress and when overlying horizons, which areinterbedded with water-saturated sandy bodies formed under the Bystrinskyclay pack during the regression cycle of sedimentation, were included inthe development. From the point of view of the analysis results, one of thepossible reasons for the development of man-made fluid contacts betweenthe injected and formation water of the overlying formation is a violationof the cement support behind the production string of the injection well.And as a result, there is a top-down flow in the production wells. Theoccurrence of disturbances in the cement support is a technical reason andcan be associated with technological processes carried out on injectionwells during operation, or imperfection in adhesion during insulation andtechnical work. The methods used in the article to determine thehydrodynamic interaction of wells and the signs of formation ofinterformation fluid contacts made it possible to assess the possiblereasons for the increase in water cut in the complex, low-permeability oilreservoirs of the Goteriv-Barremian clinoform of the Priobskysedimentation basin.

Machine-Learned Surrogate Models for Efficient Oil Well Placement Under Operational Reservoir Constraints

Summary Recent predictive analytics and soft computing methods enhanced the exploration of new hydrocarbon reserves. Machine learning (ML) has showed a promising role in oil and gas explorations in recent years. Among the applications, determining a proper location for injection and production wells along with their optimum operating conditions is a complex problem. This research aims to develop a unified process using surrogate proxy models to address this issue. Five robust ML models, (i) extreme gradient boosting (XGBoost), (ii) light gradient boosting machine (LightGBM), (iii) gradient boosting with categorical features support (CatBoost), (iv) support vector regression (SVR), and (v) multilayer perceptron (MLP), are implemented to create surrogate proxy models for estimating the net present value (NPV) of an oil reservoir. A systematic approach is used to find the best-fit hyperparameter inputs for these models. The objective of this method was to refine a broad set of hyperparameters through a random cross-validation search technique. This grid cross-validation method investigates the space narrowed in more accurate intervals. Four reservoir scenarios are considered: (i) production from a single well in a homogeneous reservoir, (ii) production from a single well in a heterogeneous channelized reservoir, (iii) production from multiple wells in a heterogeneous reservoir, and (iv) waterflooding into a heterogeneous reservoir. A reservoir simulator is implemented to create a data set of reservoir realizations with various input parameters (i.e., well location, number of wells‚ production-injection well distance, and interwell angles) in a broad range of operating conditions. The prediction of gradient boosting and MLP models showed a better fit to the simulated data with an R-squared (R2) above 95% in the first three scenarios and 75% in the fourth scenario. The results indicate that the implemented proxies are promising approaches to efficiently estimate the NPV of the reservoir models both during primary and secondary recovery scenarios.

Waterflood-induced fracture or "Two-Step-Rate-Test" to improve reservoir injectivity

Low permeability reservoirs (less than 1 mD) are developed by intensive waterflooding. The agent is injected at pressures higher than the fracturing pressure, so that in almost every well involved in this procedure, there is spontaneous growth (injection) of artificial fractures in different directions with different characteristics, and so on. The relevance of the topic is due to a new procedure called two-stage reservoir injectivity enhancement using multiple injection modes, this technique is used to determine the test fluid injection pressure at which fracture growth will occur. The problem of this study is to increase the injectivity of the injection well in order to increase fluid production. The aim and purpose of the work is the process of increasing the injectivity of injection wells by "steps" (Step-Rate-Test is SRT): a study of the Tevlinsko-Russkinskoye field. The moment of autofracturing is determined by SRT and not by injectivity. The method of interpretation is plotting. The difference between SRT and 2-SRT is considered, the 2-SRT well treatment is carried out, the efficiency of the applied method and the results of the work are presented.

Coupled hydro-mechanical simulation in the carbonate reservoir of a giant oil field in southwest Iran

The Asmari reservoir in southwest Iran has been producing oil continuously for over 50 years. However, due to an essential pressure decline, the reservoir is now a potential candidate for injection projects. The geomechanical analysis is essential for a successful injection operation to enhance reservoir production and address possible challenges. An accurate estimation of the injection pressure is necessary to maintain optimal conditions during the injection process and reduce possible risks. In this work, a coupled reservoir-geomechanical model, as well as rock mechanical tests, is performed to evaluate not only pressure variation and the associated in situ stress changes but also their potential influences on fault reactivation, reservoir–caprock stability, and surface displacement. For geomechanical evaluation, empirical correlations are derived between static and dynamic rock properties based on core data and existing petrophysical logs for the studied reservoir–caprock system. Based on the hydro-mechanical results, the maximum displacement is limited to the vicinity of the injection wells, where the highest pressure changes occur. The geomechanical analysis of the reservoir–caprock system shows that this system is stable until the injection pressure reaches 4.3× the initial reservoir pressure. Also, the injection pressure is not high enough to compromise the integrity of faults, indicating that the loading on the fault planes is too low to reactivate the pre-existing faults. The approach followed in this study can be applied to future field development strategies and feasibility considerations for CO2 sequestration and underground gas storage projects.

Mitigating seawater intrusion in coastal aquifers: Novel approach with treated wastewater injection and groundwater circulation

Seawater intrusion (SWI) is a natural phenomenon that negatively impacts the potability of groundwater and is expected to worsen with rising sea levels due to climate change. Artificial recharge of freshwater is a commonly-used remediation method to mitigate SWI and improve freshwater supply security in affected coastal aquifers. However, limited freshwater availability can limit the effectiveness of this approach. This study proposes a novel mitigation measure, called Inj-GCW, which combines the injection of reclaimed water with the use of groundwater circulation wells (GCW) to enhance the effectiveness of artificial recharge in controlling SWI. GCW is a dual-screened well with isolated screens that extract and inject groundwater into the aquifer. The performance of the proposed measure was quantitatively evaluated using an illustrative simplified unconfined coastal aquifer. Based on the findings, the design parameters were estimated for a field-scale case study of the Nile Delta aquifer (NDA), a large Mediterranean coastal aquifer in Egypt. The study adopts a future scenario that considers Sea-level rise due to climate change and projected population growth by 2100. Results demonstrate that introducing of GCWs into the saltwater wedge, along with injection, effectively retreated the saltwater wedge, due to enhanced velocity, seaward fluxes, and dilution of contamination. Inj-GCW measure led to an 8.9% reduction in SWI and a 5.2% decrease in aquifer salinity compared to the expected intrusion in 2100. Furthermore, the Inj-GCW measure resulted in a 2.2% higher repulsion rate and 0.3% reduction in total salt mass compared to injection alone. The Inj-GCW measure presents a promising solution to SWI challenges in the NDA and other coastal aquifers facing similar issues. The formation of a brackish water bubble at the injection well screen of the GCW and the generated vertical groundwater circulation cells acted as a hydraulic barrier and contributed to the proposed method effectiveness.

Minimizing exposure to legacy wells and avoiding conflict between storage projects: Exploring area of review as a screening tool

Elevated pressure from large-volume injection is a key driver of risk and project cost. If transmissive features (e.g., non-isolating wells or fracture systems) are present, increased injection-zone pressure can drive fluids from depth toward protected freshwater resources. In US Carbon Capture and Storage (CCS) law, the area at risk is known as the Area of Review (AoR). The size and number of potentially transmissive features to be evaluated and possibly remediated or managed is a function of the size and location of the AoR. The size of the AoR depends on several variables, including properties of the injection zone, properties of protected resources, and injection rate and duration. Evaluation of the intersection of these variables across a portfolio of sites highlights the injection zone depth and boundary conditions as top-level controls. Deep injection, use of multiple stacked injection zones, reduced injection rate and choice of injection well location can all be used to minimize AoR and the number of potentially transmissive features within it. We introduce the concept of pressure space (defined as connected pore volume times pressure) as the key subsurface commodity for CO2 storage and we suggest that it forms a more robust basis for leasing and regulation than pore space alone.

Intelligent Production Prediction of Deep Offshore Hydrocarbon Reservoir: A Case Study of Niger-Delta Region of Nigeria

Current methods for predicting output, such as material balancing and numerical simulation, need years of production history, and the model parameters employed determine how accurate they are. The use of artificial neural network (ANN) technology in the production forecasting of a deep offshore field under water injection/water flooding in Nigeria’s Niger-Delta region is investigated in this study. Oil, water, and gas production rates were predicted using well models and engineering features. Real-world field data from producer and water injection wells in deep offshore is used to test the models’ performance. Ninety percent (90%) of the historical data were utilised for training and validating the model framework before being put to the test with the remaining information. The predictive model takes little data and computation and is capable of estimating fluid production rate with a coefficient of prediction of more than 90%, with simulated results that match real-world data. The discoveries of this work could assist oil and gas businesses in forecasting production rates, determining a well’s estimated ultimate recovery (EUR), and making informed financial and operational decisions.

Experimental Study on Multi-Dimensional Visualization Simulation of Gas and Gel Foam Flooding in Fractured-Vuggy Reservoirs.

Gas flooding and foam flooding are potential technologies for tertiary oil recovery in fractured-vuggy reservoirs. The development and mechanism research of fractured-vuggy reservoirs is difficult due to the complex structures and the strong heterogeneity of fractured-vuggy reservoirs. Visualization simulation is one of the effective methods to study the flow behavior of fluid in fractured-vuggy reservoirs. In this study, an upscaling method of visualization simulation from one dimension (1D) to three dimensions (3D) was established, and the physical models of fractured-vuggy reservoirs were designed and fabricated. Water flooding, gas flooding, and gel foam flooding were carried out in the models. The experimental results showed that gas flooding has a single flow channel and water flooding has multiple flow channels in fractures and vugs. Gel foam with an excellent capability of mobility control and a high microscopic displacement efficiency swept in all directions at a uniform velocity. The EOR mechanisms of gel foam in fractured-vuggy reservoirs were mainly as follows: reducing interfacial tension, increasing mobility ratio, selectively plugging high permeability channels, and discontinuous flow. In the displacement process of fractured-vuggy reservoirs, water should be injected from the well at the bottom of the reservoir, and gas should be injected from the well located in the vug at the high part of the reservoir. Gel foam with strong stability and high viscosity should be selected and injected in most kinds of injection wells in fractured-vuggy reservoirs. This study provides a complete method of visualization simulation for the study of flow behavior in fractured-vuggy reservoirs and provides theoretical support for the application of gas flooding and gel foam flooding in fractured-vuggy reservoirs.

Performance Analysis of Water Injection Well BEL-13 and Production Well BEL-01 Using Hall Plot and Buckley-Leverett Methods

At first, the FLO field had an ability to flow fluids to the surface in a natural flow, but the production capacity decreased with time. Therefore, production is increased using the waterflooding method. The purpose of this study was to analyze the performance of waterflooding carried out on injection well BEL-13 and production well BEL-01. There are two methods used in this study to achieve the desired aims and objectives, namely the Hall Plot method and the Buckley-Leverett method. The Hall Plot method was used to see the connectivity conditions between injection and production wells after being injected with water periodically. Whereas the Buckley-Leverett method was used to estimate the time of water breakthrough, production amount (Np), the injection rate (Wi), water cut value (WC), and recovery factor (RF). Based on the Hall Plot method, it was found that the waterflooding carried out was stable or normal because there was no negative skin or positive skin. In addition, based on relative permeability curve, rock wettability of the reservoir rock is water wet. Analysis using Buckley-Leverett shows that the cumulative production at the time of water breakthrough from the injection well BEL-13 to the production well BEL-01 is 364,733.64 STB. When the water breakthrough occurs, the predictions of WOR, water cut, and recovery factor are 2.13, 68.08%, and 29.76%.

Well placement optimization with a novel swarm intelligence optimization algorithm: Sparrow Search Algorithm

Well placement optimization plays a critical role in developing oil and gas reservoirs, presenting a formidable challenge due to the high dimension of the search space and computational requirements. This research addresses the simultaneous optimization of well location and flow rates for production and injection wells in a heterogeneous oil reservoir located in southwestern Iran. The objective function employed to evaluate the proposed solutions generated by the Sparrow Search Algorithm (SSA) is the net present value (NPV). To enhance the performance of SSA, a sensitivity analysis is conducted to tune its hyperparameters, while keeping the epochs and population size fixed to manage runtime effectively. The study tackles the challenges posed by reservoir heterogeneity and the time-consuming nature of the optimization process through various strategies. The decision variables are reduced to a reasonable order, and a quality index is introduced to guide the algorithm towards exploring areas of the reservoir with higher potential. Furthermore, runtime is utilized as a termination condition to optimize computational time. The inclusion of the quality map significantly improves the NPV outcomes, allowing for more effective well placement decisions. Physical constraints related to well placement are handled using a penalty method and map cleaning techniques. Having addressed these challenges, the study investigates the impact of fixed parameters on the optimization results. By conducting an optimization run with 100 epochs, comparable outcomes to the case of 50 epochs (with a 5% improvement) are achieved, albeit with a longer runtime of 20 h. However, increasing the population size substantially raises both runtime and computational costs. Therefore, runtime is considered a practical termination condition, and efficient runtimes of 10 and 15 h are selected for this specific problem. The results indicate that a population size of 25 sparrows outperforms the cases with 50 and 100 epochs, respectively, yielding slightly higher NPV values. Furthermore, the performance of SSA is compared to that of Particle Swarm Optimization (PSO) in terms of NPV, convergence, and runtime. The results highlight the advantages of SSA, demonstrating faster convergence and achieving higher NPV values compared to PSO. However, the computational cost of SSA should be taken into consideration, as it requires significantly more time to reach the optimal solution compared to PSO. Overall, this research emphasizes the high potential of the SSA algorithm for optimizing well placements and its practical relevance in real-world oil industry cases.

The method of non-stationary flooding and the conditions for its effective use in the operation of an oil field

The article describes the essence of unsteady waterflooding, which is one of the most effective methods of increasing the oil recovery factor, used to change the direction of filtration flows, which makes it possible to engage in the development of undeveloped oil reserves and reduce the rate of watering of the deposit in productive reservoirs. A common technological method of unsteady water flooding is the use of cyclic modes of operation of injection wells. The essence of this method is that at an unsteady state in the oil deposit, there are conditions for the continuous manifestation of elastic forces of the reservoir system. In a heterogeneous reservoir between different zones, channels, and fluid flows there are gradients of hydrodynamic pressures, due to which there can be fluid flows from one layer to another, from fractures to blocks, as well as changes in flow directions. During unsteady flooding of heterogeneous formations, a part of oil reserves in low-permeability layers or zones remains uncovered by injected water. The waterflooded reservoir appears as an unsystematic alternation of watered and oil-saturated microflows. While creating in such reservoirs alternately changing in value and direction of pressure gradients, conditions for injection water penetration into stagnant oil-saturated low-permeable zones and channels appear in the oil reservoir and oil movement from them to active drainage zones. As a result of the analysis, the positive effect of the implementation of unsteady waterflooding technology was revealed, and recommendations for improving its application at other operational facilities of oil fields were given.