Reservoir Production Research Articles

Assessment of Production Performance and Uncertainty in the UBGH2-6 Gas Hydrate Reservoir, Ulleung Basin

This study delineates the intricate dynamics of gas hydrate production in the UBGH2-6 reservoir, located in the Ulleung Basin, by deploying a comprehensive simulation model. By integrating a sensitivity analysis with Latin hypercube sampling-based Monte Carlo simulations, we evaluated the influences on gas and water production and explored the underlying uncertainties within this gas hydrate reservoir. The simulation model revealed significant findings, including the production of approximately 440 t of gas and 34,240 t of water, facilitated by a depressurization strategy at 9 MPa for a year. This highlights the pivotal roles of porosity, permeability, and thermal properties in enhancing production rates and influencing hydrate dissociation processes. Sensitivity analysis of 19 parameters provides insights into their impact on production, identifying the key drivers of increased production rates. Furthermore, uncertainty analysis examined 300 reservoir models, utilizing statistical percentiles to quantify uncertainties, projecting a median gas production of approximately 455 t. This study identifies critical factors affecting gas hydrate production and offers valuable insights for future exploration and exploitation strategies, making a significant contribution to the field of gas hydrate research.

Preparation of Low-Viscosity Epoxy Resin Sealing Agent and Evaluation of Injection, Plugging, and Degradation Properties.

The technology of water plugging and increasing production in high water cut reservoirs of low permeability is a common problem in the industry. Epoxy resin, displaying excellent mechanical properties and adherent performance, can easily inject a tiny crack, forming a long-term blocking barrier. This study aimed to investigate an easily injectable degradable epoxy resin sealing material. The injectable performance, long-term stability, and mechanical and plugging properties were comparatively analyzed in the fractured core, and the degradable performance was discussed in the degrading solution. The result showed that the range of R (R is the ratio of EOG and MHHPA) from 1 to 1.1 and the mass fraction range of EMI from 0.01 to 4 wt % are the optimal formulations (EOGM). The curing time from 1 to 12 h could be regulated by adjusting the dosage of EMI, as well as the strength being more than 60 MPa. The plugging agent's initial viscosity is lower than 100 MPa s at 20 °C and injecting pressure is lower than 0.1 MPa. After curing for 24 h, compressive strength was more than 72.76 MPa, 3.6 times higher than that of cement, and the adhesion strength was 4.41 MPa when the contact area was 75.93 cm3. Breakthrough pressures for sealing 1-5 mm fractures were all more than 10 MPa, and the breakthrough pressure for 1 mm crack even reached 29.4 MPa. Epoxy resin/acid anhydride system could be degraded in a mixed solution of phenol-potassium salt-heavy aromatics within 7 days at 60-100 °C, which reduced the plugging well risk of the epoxy resin plugging agent. These results suggest that an epoxy resin/acid anhydride plugging agent can be employed effectively and safely for the injection of tiny cracks, which is of great engineering significance.

Numerical Simulation of Fracturing Fluid Storage in Shale Reservoirs Based on Experimental Measurements of Stress Sensitivity of Hydraulic Fracture Network Conductivity

Hydraulic fracturing is used in shale reservoir production, with low flowback rates and a large amount of fracturing fluid retained inside the reservoir. In this study, a stress sensitivity analysis experiment on the fracture inflow capacity was implemented to investigate the relationship between the hydraulic fracture (HF) and natural fracture (NF) inflow capacities and effective stress. A three-dimensional shale reservoir model was also constructed to couple the experimentally obtained laws with the numerical model to investigate the effects of the connection and closure of the fracture network on the retention of the fracturing fluid. The results show that the stress sensitivity of natural fractures is two orders of magnitude higher than that of hydraulic fractures. The seepage-absorption effect of capillary forces is not the whole reason for the large amount of fracturing fluid retention. The closure of the fracture network formed by natural and hydraulic fractures during the production process led to the storage of a large amount of fracturing fluid, and this process maintained the stability of the water production rate during the steady water production period.

Development and field application of strongly resilient temporary plugging diversion agent for fracturing

Temporary plugging diversion fracturing in multistage horizontal well is normally used to improve stimulation efficiency and increase production in unconventional reservoirs. Temporary plugging agent plays an important role in diversion fracturing. A strongly resilient temporary plugging diversion agent can improve the effectiveness of fracturing diversion. Therefore, a novel organosilicon temporary plugging diversion agent (QBZU) was developed through micellar copolymerization method. Self-synthesized strongly resilient temporary plugging diversion agent (QBZU gel) was prepared by using acrylamide, N, N′-methylene bisacrylamide, surfactants, organosilicon, ammonium persulfate and sodium bisulfite as chemical raw materials. The micellar copolymerization is investigated to overcome the incompatibility of hydrophobic organosilicon and water-soluble monomer by adding some appropriate surfactants. The experimental results indicated that the combination of sodium dodecyl sulphonate and Tween 80 provided excellent copolymerization results. The characteristics of compressive resistance, salt resistance, shearing resistance, resilience and degradation are superior compared with traditional rigid granular temporary plugging agent widely used in oilfields (QG hydrogel). According to the experimental evaluation results of QBZU, its pressure-bearing capacity can reach 56.3MPa, shearing strength can reach 410N, elastic modulus can reach 80MPa, and Poisson ratio can reach 0.48. Meanwhile, the main synthetic factors affecting the resilient performance of QBZU were investigated, including polymer concentration, organosilicon concentration and the types of surfactant. Based on the fracturing pressure curve and microseismic monitoring results, the plugging and fracture diversion effectiveness was further confirmed.

Dynamics of Water Sighting and Injection Mechanisms in Fishbone Branch Wells in Bottom Water Reservoirs

Abstract Herringbone wells are effective in improving productivity for bottom water reservoirs; however, the main problem faced in the exploitation of bottom water reservoir is the ridge and cone of bottom water during the process of waterflooding, which leads to the decline of oil production. Therefore, predicting the breakthrough time and location of herringbone wells in bottom water reservoirs and then adjusting the water injection measures are of great significance for improving production and development. In this paper, we establish a three-dimensional coning model of bottom water to study the dynamic performance of bottom water rise, and the sequence of breakthrough position is determined by studying the breakthrough time along the wellbore. Based on the reservoir numerical simulation, we carry out a comprehensive adjustment of the water injection mechanism and develop a water injection scheme under the combination arrangement of vertical wells and herringbone wells. The results show that the bottom water breakthrough position of the branch well is mainly near the heel of the main branch or near the middle subsidence, and the recovery rate is the highest when the branch angle is 45 deg. The longer the shut-in time, the higher the recovery. The study is of great significance to optimize the layout and spatial structure, determine a reasonable working system, delay water channeling, and increase the cumulative production of herringbone wells.

A Method to Identify Pore Fluids in Heterogeneous Conglomerate Reservoirs Using a Nuclear Magnetic Resonance Log with Oil-Based Mud Invasion

Summary Nuclear magnetic resonance (NMR) logging has been extensively utilized for identifying pore fluids in recent years. However, after oil-based mud (OBM) invasion, OBM filtrate partially takes the place of the original fluid in the reservoir and the morphology of the NMR T2 (transverse relaxation time) spectrum changes. OBM invasion makes it difficult to identify the formation fluid using routine NMR fluid identification methods. In this study, we took heterogeneous conglomerate formation in the northwestern Junggar Basin as a case study and carried out core experiments under four conditions (viz., water-saturated, OBM displacing water, oil-saturated, and OBM displacing oil) and simulated the states of OBM invasion into water and hydrocarbon-bearing formation. Comparative analysis finds that when the OBM invades the water layer, the movable peak of the T2 spectrum primarily reflects the bulk relaxation characteristics of OBM filtrate, whereas when the OBM invades into the oil layer, the T2 spectrum may exhibit a three-peak distribution, where the first peak mainly indicates irreducible water, the second peak reflects OBM filtrate, and the third peak primarily reflects nondisplaced oil. To facilitate fluid identification, two T2 cutoffs are adopted to divide the T2 spectrum into three segments, and combined with the T2 geometric average, a fluid identification factor (ifluid) is proposed. Finally, identification criteria for reservoir type are established on the NMR logging and drillstem test data. The field application verifies the reliability of the proposed methods. These methods realize the identification of oil layers under OBM drilling and guide the subsequent production and development of oil reservoirs.

Characterization of the Gas-Bearing Tight Paleozoic Sandstone Reservoirs of the Risha Field, Jordan: Inferences on Reservoir Quality and Productivity

Characterization of the Gas-Bearing Tight Paleozoic Sandstone Reservoirs of the Risha Field, Jordan: Inferences on Reservoir Quality and Productivity

Analysis of the Production Characteristics of Heterogeneous Reservoirs Assisted by Shallow Gas by Depressurization Path

The problems of low gas production rate and low gas production restrict the commercial production of natural gas hydrate. The combined production of hydrate reservoirs and underlying shallow gas reservoirs is expected to make up for this shortcoming. Most natural gas hydrates in the formation exhibit vertical heterogeneous distribution characteristics; There is still little research on the mechanism of its impact on the characteristics of co harvesting. This work focuses on the interaction between vertical heterogeneous hydrate reservoirs and shallow gas layers, and analyzes the mechanism of the impact of depressurization pathway on the characteristics of combined production. The results indicate that before the pressure in the shallow gas layer is equal to the pressure in the hydrate layer, the change in pressure reduction method cannot significantly affect the characteristics of pressure changes in the shallow gas layer; In addition, there is a significant hysteresis effect in the pressure evolution of shallow gas layers compared to hydrate layers. Not limited to this, the presence of shallow gas layers will also weaken the impact of pressure reduction paths on the gas production characteristics of combined production, which makes the gas production characteristics at this time more inclined towards the gas production characteristics under direct pressure reduction. In summary, in order to effectively increase the temperature of shallow gas and enhance hydrate decomposition, it is necessary to flexibly adjust the pressure reduction indicators of the pressure reduction path in different mining stages. The results can lay the foundation for clarifying the mechanism of interlayer interference in multiple gas source reservoirs.

Formation mechanical mechanism of low-angle fractures in pre-salt carbonate reservoirs: a case study from Carboniferous KT-I formation of the NT oilfield in the eastern margin of the Precaspian Basin, Kazakhstan

Fracture is an important factor that affects the oil and gas productivity of carbonate reservoirs. Much researches have been done on the origin of high-angle fractures in carbonate reservoirs, but few efforts have been made on the genetic mechanical mechanism of low-angle fractures. Based on the seismic data, core data, conventional logging data and rock mechanics experimental data, combined with three-dimensional in situ stress field simulation methods, the features, formation geological conditions and genetic mechanical mechanism of low-angle fractures (LAFs) were analyzed by applying Coulomb–Moore criterion, Griffith criterion and non-coordination criterion. The proportion of the number of shear fractures is as high as 90.2%, while that of tensile fractures is only 9.8% in the study area. Shear fractures are mainly unfilled fractures, and tensile fractures are mainly partially filled fractures. The LAFs were formed in the second tectonic movement, in which the knee-fold structure with high in the west and low in the east developed in the study area. The buried depth of most parts of the KT-I formation is 800 m when the study area develops the knee-fold structure, with a maximum depth of 1800 m and a minimum buried depth of 70 m, and the dip angle of the steepest part of the stratum is about 20°. A large number of LAFs were formed in the study area under the joint influence of tectonics and abnormally high pressure of water, including near-horizontal LAFs in the non-weak fabrics section (type I low-angle shear fractures), the LAFs having a certain angle with bedding in the non-weak fabrics section (type II low-angle shear fractures) and near-horizontal LAFs in the weak fabrics section (type III low-angle shear fractures). The formation of type I and type II low-angle shear fractures follows the Coulomb–Moore criterion. Type I low-angle shear fractures are formed in strata with a certain dip angle, while type II low-angle shear fractures are formed in near-horizontal strata. Type III low-angle shear fractures are formed under the comprehensive influence of pre-existing weak fabrics and strong horizontal extrusion, which follows the non-coordination criterion. Low-angle tensile fractures are mainly caused by abnormally high pressure and reverse faults in the study area, following Griffith’s criterion. The research in this paper not only reveals the formation mechanical mechanism of LAFs in pre-salt carbonate reservoirs but also provides guidance for the prediction of LAFs and solving the problem of water channeling caused by LAFs in oil fields.

Time-dependent model for two-phase flow in ultra-high water-cut reservoirs: Time-varying permeability and relative permeability

For the ultra-high water-cut reservoirs, after long-term water injection exploitation, the physical properties of the reservoir change and the heterogeneity of the reservoir becomes increasingly severe, which further aggravates the spatial difference of the flow field. In this study, the displacement experiments were employed to investigate the variations in core permeability, porosity, and relative permeability after a large amount of water injection. A relative permeability endpoint model was proposed by utilizing the alternating conditional expectation (ACE) transformation to describe the variation in relative permeability based on the experimental data. Based on the time dependent models for permeability and relative permeability, the traditional oil-water two-phase model was improved and discretized using the mimetic finite difference method (MFD). The two cases were launched to confirm the validation of the proposed model. The impact of time-varying physical features on reservoir production performance was studied in a real water flooding reservoir. The experimental results indicate that the overall relative permeability curve shifts to the right as water injection increases. This shift corresponds to a transition towards a more hydrophilic wettability and a decrease in residual oil saturation. The endpoint model demonstrates excellent accuracy and can be applied to time-varying simulations of reservoir physics. The impact of variations in permeability and relative permeability on the reservoir production performance yields two distinct outcomes. The time-varying permeability of the reservoir results in intensified water channeling and poor development effects. On the other hand, the time-varying relative permeability enhances the oil phase seepage capacity, facilitating oil displacement. The comprehensive time-varying behavior is the result of the combined influence of these two parameters, which closely resemble the actual conditions observed in oil field exploitation. The time-varying simulation technique of reservoir physical properties proposed in this paper can continuously and stably characterize the dynamic changes of reservoir physical properties during water drive development. This approach ensures the reliability of the simulation results regarding residual oil distribution.

Real-Time Prediction of Petrophysical Properties Using Machine Learning Based on Drilling Parameters.

The prediction of rock porosity and permeability is crucial for assessing reservoir productivity and economic feasibility. However, traditional methods for obtaining these properties are time-consuming and expensive, making them impractical for comprehensive reservoir evaluation. This study introduces a novel approach to efficiently predict rock porosity and permeability for reservoir assessment by leveraging real-time machine learning models. Utilizing readily available drilling parameters, this approach offers a cost-effective alternative to traditional time-consuming methods to predict formation petrophysical parameters in real-time. The data set used in this study was collected from two vertical wells located in the Middle East. It encompasses drilling parameters such as the rate of penetration (ROP), gallons per minute (GPM), revolutions per minute (RPM), strokes per minute (SPP), torque, and weight on bit (WOB), along with the corresponding measurements of porosity (ϕ) and permeability (k) obtained through core analysis. Three machine learning models, namely, decision trees (DTs), random forest (RFs), and support vector machines (SVMs), were employed and evaluated for their effectiveness in predicting porosity and permeability. The results demonstrate promising performance across the different data sets. All three models achieved correlation coefficients (R) higher than 0.91 in predicting porosity. The RF model exhibited accurate predictions of permeability, achieving R values surpassing 0.92 in the various data sets. While the DT model displayed slightly lower performance, with the R-value decreasing to 0.88 in the testing data set, the SVM model suffered from overfitting, with R values dropping to 0.83 in the testing data set. The novelty of this work lies in the successful application of machine learning models to the real-time prediction of reservoir properties, providing a practical and efficient solution for the oil and gas industry. By achieving correlation coefficients exceeding 0.91 and showcasing the models' efficacy in a dynamic testing data set, this study paves the way for improved decision-making processes and enhanced exploration and production activities. The innovative aspect lies in the utilization of drilling parameters for timely and cost-effective estimation, transforming conventional reservoir evaluation methods.

Study on rock strength weakening in multi-stage acid fracturing using continuous strength test

Multi-stage acid fracturing can boost productivity in low-permeability limestone reservoirs, with success hinging on differential etching and the strength of undissolved regions to keep fractures open. Traditional rock strength test methods have strong randomness and error. This study explores the influence of four acid systems (hydrochloric acid, single-phase retarded acid, gelled acid, and emulsified acid) on fracture surface strength based on a new continuous strength test method. The rock strength weakening variation under different acid types and injection conditions was quantified, and the mechanism of single-phase retarded acid slowing down rock strength reduction was revealed. The results indicated that the fracture surfaces were reduced to a lesser extent than in traditional rock mechanical failure studies. Hydrochloric acid caused up to 28% of rock strength depletion, followed by 23% for gelled acid, 18% for emulsified acid, and 11.8% for single-phase retarded acid. Adjusting the acid injection parameters revealed that longitudinal leak-off at the fracture surface changes the rock's strength failure tendency. The microscopic results confirmed that the appropriate acid-rock reaction rate and viscosity are beneficial in reducing strength by forming the dominant wormhole that “siphons” the subsequent acid more profoundly into the formation, thereby reducing the reaction of the acid with the fracture surface. This study can help to understand better the mechanism by which acid reduces the strength of fracture surfaces and can provide guidance for selecting appropriate acid fluids for acid fracturing in low-permeability limestone reservoirs.

A Grand Challenge Update: Geothermal Energy

_ This is the first of a series of six articles on SPE’s Grand Challenges in Energy, formulated as the output of a 2023 workshop held by the SPE Research and Development Technical Section in Austin, Texas. Described in a JPT article last year, each of the challenges will be discussed separately in this series: geothermal energy; improving recovery from tight/shale resources; net-zero operations; carbon capture, storage, and utilization; digital transformation; and education and advocacy. _ SPE identified five technical “Grand Challenges” in 2023 which, if successfully developed, could advance the interests of the SPE community in a net-zero world and help ensure our longevity and contributions to a prosperous future (Halsey et al. 2023). Access to the subsurface is a key skillset of the SPE community, including geology and geophysics, well construction and completion, reservoir engineering, production operations, and facilities. The challenges that geothermal faces to become a leading player in the net-zero world are well within the areas of expertise of the SPE community, ranging from rapid technology implementation and learning-by-doing to assure competitiveness, to establishing suitable funding mechanisms to secure access to capital. The increasing presence of geothermal-related sessions in SPE workshops and conferences shows the interest to explore novel methods to harness geothermal energy for power supply, thermal-use applications, and energy storage, illustrated by the threefold increase in OnePetro references since 2020 (Fig. 1). The Role of the Oil and Gas Industry Geothermal energy offers a path forward using business models that are well-suited to the oil and gas industry, which can apply its current technology and expertise to produce clean, reliable power and thermal energy at scale. Geothermal is also the only baseload renewable energy source that produces heat, presenting an avenue to mitigate the largest contribution humanity makes to carbon emissions: heating and cooling which account for 40% of all carbon emissions globally (Lund and Toth 2021). Table 1 presents some of the current applications. In 2023, the Energy Institute of The University of Texas at Austin released a comprehensive report, “The Future of Geothermal in Texas,” led by Project InnerSpace (Beard and Jones 2023). The report presented a challenge to leverage the technical capabilities and resources in the state. It estimated that “should the industry drill 15,000 geothermal wells each year for four years, it would provide the energy equivalent of all oil and gas used for electricity and heat production in the State today, including industrial heat.” This initiative is part of a broader movement in Texas, the spiritual home of the US fossil fuel industry, where a new geothermal energy ecosystem is emerging with veterans of the oil and gas business playing pivotal roles. Geothermal energy cannot only help to reduce the state’s emissions but also through its baseload and energy storage capabilities, it can support a power grid that has struggled to cope with severe weather events as demand has grown. Texas serves as a prime example of a location deeply tied to fossil fuels, where numerous oil and gas developers are announcing plans for geothermal expansion. This trend is not confined to Texas alone; similar developments are underway in other US states, Europe, the Middle East, and the Far East.

A STATISTICAL ANALYSIS OF GEOLOGICAL AND ENGINEERING PREDICTORS OF OILFIELD PERFORMANCE RESPONSE: A CASE STUDY OF OILFIELDS ON THE UK CONTINENTAL SHELF

Oilfield production is controlled by a wide range of geological and engineering parameters, many of which are at least partially interrelated. This paper uses multivariate statistical methods (principal component analysis, regression analysis and analysis of variance) to determine how these parameters are related, and which of them are most significant in controlling and predicting oilfield performance. The analysis is based on a database of publicly available oilfield data from the United Kingdom Continental Shelf (UKCS), from which a series of geological, engineering and fluid‐related control variables from 136 fields were pre‐processed and analyzed. This dataset is a subset of a much wider project database for UKCS oil, gas and condensate fields. For this study, the project database was divided into two datasets: a first dataset with 10 parameters from 136 fields, and a second, more detailed dataset with 27 parameters from 38 fields. Both datasets were analysed using principal component analysis in order to investigate possible correlations between numerically/statistically interrogable predictor variables such as porosity, permeability, number of production wells, gas‐oil ratio and reservoir temperature. A regression analysis was then carried out on the predictor variables in order to obtain a ranking of predictability (i.e. how indicative a predictor is of a particular outcome) and sensitivity (how sensitive an outcome is to slight changes in a predictor) in relation to recovery factor based on R‐squared and regression coefficient values. The results showed that key variables from the principal component analysis included field size, number of production wells, PVT, gross depositional environment and reservoir quality. High‐ranking parameters of predictability and sensitivity from the regression analysis were found to include API, net‐to‐gross, porosity and reservoir depth. These results are consistent with previous studies and suggest that it should be possible to forecast oilfield recovery based on only a few selected input variables. As a preliminary test of forecasting ability of the variable permutations put forward, a best‐subsets multiple regression was carried out using a statistical software package and yielded results which corroborated the main findings.

A Method for Evaluating Coalbed Methane Reservoir Productivity Considering Drilling Fluid Damage

In the process of coalbed methane development, drilling fluid and fracturing fluid cannot achieve absolute compatibility with formation. The incompatibility between the working fluid and reservoir will lead to the intrusion of working fluid into the reservoir and cause reservoir pollution. This is a very common phenomenon. There is a large amount of pulverized coal in the coal seam, and the intrusion of working liquid will be combined with the pulverized coal to form cement to block the seepage space in the reservoir. Since pressure relief and fracturing fluid backflow will be performed at the first time after fracturing, the intrusion range of the working fluid is small, generally reaching 10 m to 50 m. Compared with a conventional gas reservoir or shale gas reservoir, the working fluid loss during CBM development will seriously affect the subsequent production project and even make the gas well lose production capacity. On the other hand, in order to avoid this phenomenon, measures such as acidification or volumetric fracturing are sometimes used to improve the seepage environment near the well and near the fracture. The purpose of this study is to quantitatively evaluate the impacts of working fluid filtration and reservoir reconstruction on production. In this study, a single well productivity evaluation model and sensitivity analysis method considering drilling fluid filtration loss, fracturing fluid filtration loss, reservoir reconstruction and other processes is proposed. The formation mechanism of fluid loss during drilling and fracturing is described, and the productivity evaluation model considering fluid loss is combined with the Langmuir isothermal adsorption equation, steady-state diffusion law, Darcy’s seepage law and Duhamel convolution formation. Combined with the distribution of actual gas reservoir flow characteristics, the sensitivity of single well productivity to gas reservoir porosity, gas reservoir permeability, coal seam adsorption coefficient, working fluid filtration loss and reservoir reconstruction measures are analyzed. Through the analysis and fitting of the actual production data on site, the relationship curve can better fit the field production data, and the evaluation results are in line with the drilling and fracturing conditions at that time and the subsequent production conditions, with small errors. The obtained method is suitable for predicting the productivity of fractured vertical wells in different working conditions and provides a basis for the development and productivity prediction of CBM reservoirs in China and in international cooperation.

Optimizing filtration properties of water based drilling mud systems using dually modified starch

This research explores the efficacy of dually modified starch as a fluid loss controlling agent in drilling mud systems, aiming to optimize filtration properties for improved borehole stability and reservoir productivity. Filtrate loss and filter cake thickness (API and HPHT) were examined under varying conditions, focusing on the influence of degree of substitution (DS) of the starch, CMITS concentration, salt concentration, and temperature. The current findings reveal that DS 0.66 starch exhibited the highest reduction in filtrate volume and cake thickness, achieving an 81% decrease at 8 ppb concentration. Regression models accurately predicted filtration properties and were confirmed through additional experiments. Comparison with previous studies underscores the potential of modified starch as a cost-effective alternative for drilling mud additives. Furthermore, the correlation between viscosity and filtration properties was explored, highlighting its impact on improved filtration characteristics. Overall, this research contributes valuable insights into enhancing drilling efficiency and borehole stability, minimizing dependence on costly chemical additives.

Maximizing Production Profits: Optimizing Gas Lift Design in the Halfaya Oil Field

Gas lift is one of the most common artificial lift methods which is effectively utilized in the oil industry for enhancing production. However, proper gas allocation into wells can be challenging due to various limitations such as shortage in injected gas and economic considerations. Therefore, the current research is conducted to address the critical requirement to effectively distribute gas to maximize profits in the Halfaya Oil Field- Mishrif formation. Continuous gas lift is one of the most commonly used artificial lift methods. To enhance production rate, a sufficient amount of gas is injected into the production tubing at specific depths to reduce the liquid column pressure as each well has an optimal point for production in an oil reservoir. On the other hand, constraints of gas availability restrict achieving the optimal state of production. Such restrictions combined with economic limitations including high gas prices and compression costs, emphasized the necessity for optimal methodology to enhance oil production. Aside from the importance of the Halfaya oil field, there are limited relevant studies on artificial lifting methods specifically associated with the gas-lifting method used in this paper. Thus, the purpose of the current investigation is to propose a well-tested gas lifting design for oil production improvement. The approach combines the skill of the fmincon function built in MATLAB as an optimizer and the PIPESIM network model to create gas lift performance curves. This resulted in an oil production rate of 18860 STB/d, with a gas lift rate of 9.42 mmscf/d. Establishing such a systematic optimization process can manage the challenges of gas allocation in the Halfaya Oil Field towards maximizing production rates and ultimately increasing net profits.

Modified approach to calculate brittleness index in shale reservoirs

The successful production of unconventional reservoirs through hydraulic fracturing is heavily dependent on the brittleness of the shale's. To precisely evaluate rock brittleness the mineral-based brittleness indices are considered reliable. Initially, only the weight fraction of quartz accounted for mineralogical brittleness, later dolomite was included in the group, further, it was divided into the silicate and carbonate groups. Due to its heterogeneous nature, shales contain some other minerals, however, the impact of these minerals on rock brittleness has yet to be analyzed. The mineral pyrite is commonly found in shales but its impact on rock brittleness is still undefined. In this research, we proposed a modified mineral-based brittleness index including mineral pyrite, and investigated its impact on rock brittleness. The modified index was evaluated using the data from three different shale reservoirs in China. In the next step, the Fracability Index (FI) model of rocks including pyrite mineral is calculated, and finally, the rock physics modeling is performed to evaluate the elastic response of the rock to this mineral. The modified brittleness index was found to be more accurate in predicting rock brittleness than other mineral-based brittleness indices. The correlation between the modified brittleness index and the FI model was higher than the correlation with other mineral-based brittleness indices. Further, rock physics modeling also proved that the rock with high pyrite content has low Poisson's ratio and high Young's modulus.. These properties are associated with brittle rocks, which further supports the inclusion of pyrite as a brittle mineral in the modified brittleness index. Hence, the findings of this research indicate that the modified brittleness index based on minerals is a reliable approach for predicting rock brittleness in shale reservoirs that contain pyrite. This study has an important application for the development and management of shale reservoirs. The modified brittleness index can be used to identify rocks that are more likely to be successfully fractured during hydraulic fracking process. Keywords: shale reservoirs; hydraulic fracturing; mineral brittleness; fracability index.

An enhanced oil recovery technology applicable to kazakhstan reserves with highly viscous oils

The subject of discussion of the article below is polymer flooding as an EOR (enhanced oil recovery) technique considered here within the context of Kazakhstan’s depleted oil-fields exploitation. The underlying factor for considerable residual hydrocarbon saturation observed in the productive reservoirs of the majority of Kazakhstan’s oil fields connected with their stratified heterogeneous structures. Such kind of Oil Reservoirs require additional developments comprising new technologies promoting enhanced oil-recovery. Keywords: viscosity; inhomogeneity; polymer flooding; polyacrylamide; degree of inhomogeneity; permeability; catholyte; trim.

Technological efficiency of applying viscoelastic systems for temporary blocking of productive reservoir when completing wells under conditions of abnormally low formation pressures

The article examines the technical and economic aspects of well killing under conditions of abnormal low reservoir pressure (ALRP). The possibility of joint use of compositions for temporary blocking of a productive formation, having different functional abilities to plug fluid-conducting channels, has been studied. Requirements for blocking fluids (BF) for killing during repair works in wells with excess ALRP have been formulated. The results of research and technical solutions in the field of development of viscoelastic systems for temporary blocking of productive formations in wells in conditions above the ALRP are presented. The results of laboratory and bench studies on the development of a gel-forming destructuring polymer-based biosol and fillers are presented. The advantage of using a destructurable biological fluid for temporary blocking of a productive formation in conditions above the maximum pressure limit using chemical reagents belonging to the following groups: polymers, salts, surfactants, acids, alkalis and fillers has been analyzed. The results of determining the mechanical properties of the resulting BF gel are presented. A gel-forming composition has been proposed that has high blocking properties and an optimal formulation of an alkaline destructor that ensures the destruction of the gel based on gammaxan. Formulations of viscoelastic destructurable fluids for killing wells in conditions exceeding the ALRP have been recommended for practical use. Keywords: well; bottomhole formation zone; blocking; blocking fluids; viscoelastic compositions; destructuring; ALRP.