Average Reservoir Research Articles

Identifying boundary conditions of an oil reservoir flow model from well pressure measurements. Part 1: Homogeneous reservoir

A method was outlined for determining the coefficient of third-kind boundary conditions of the piezoconductivity problem in an oil reservoir, particularly on its external contour, which has, as a rule, no specific hydrodynamic properties and is set to reduce computational costs. The coefficient was determined using an integral balance model of an interaction between the oil deposit and the outer region of the reservoir. The optimization problem of approximating the average reservoir pressure to the values obtained from the well pressure measurements was solved. Assuming the homogeneity of the reservoir, the applicability of the algorithm was assessed under various geometries of the external contour, well placements, and operating conditions. The stability of the algorithm for solving the inverse problem was analyzed against pressure measurement errors. The proposed approach offers a relatively simple algorithm for defining the boundary conditions of a reservoir flow model, which enables a good approximation of the hydrodynamic interaction of the reservoir with its outer region. However, due to uncertainties in the initial data for regions distant from the well-drilled area of the reservoir, significant difficulties remain in calibrating the model.

CGDS near-bit geosteering drilling system and its first application in Niger

Abstract The Niger project is one of the important exploration and development cooperation projects of China National Petroleum Corporation in West Africa. The Dibeilla N-1 block of Agadem oilfield in Niger faces challenges such as frequent interlayers and susceptibility to encountering faults during drilling. According to the deployment requirements of the plan, the block will be developed using a mixed well network of horizontal and vertical wells, and the upper sand body will need to be developed using horizontal wells. The dogleg angle of the inclined wellbore should be controlled within 2∼4.5 (°)/30m, and the target thickness should be only 3m. Conventional guiding tools represented by MWD(Measurement While Drilling) cannot achieve effective and efficient reservoir identification and trajectory adjustment in thin oil layers due to their zero length of around 10 meters. Therefore, a geological guiding tool that can achieve near drill bit measurement is needed. Therefore, in order to successfully complete the horizontal section drilling and guidance engineering, maximize the drilling encounter rate of high-quality reservoirs, communicate favorable layers to achieve oil reservoir benefit development, it is decided to use CGDS(CNPC Geological Drilling System)near bit geological guidance tool to implement horizontal section drilling. The system is equipped with gamma, resistivity, and engineering parameter measurements at a distance of 3 meters from the drill bit, providing multiple basis for precise directional guidance of the formation. In the Dibeilla N-1 block of Niger, a total of 6 wells were applied, with an average reservoir drilling encounter rate of 85.38% and a mechanical drilling speed of 12.31 m/h. The first application of this system overseas has provided valuable experience for similar domestic work.

تصميم نظام غمر المياه لحقل الدفا النفطي

Currently, water-flooding is responsible for a big portion of world oil production. The vertical sweep efficiency and the areal coverage each of these requires careful sampling to get represented reservoir rock and fluid properties measures of reservoir heterogeneity, Economically, a pilot is a desirable tool for studying oil recovery performance on reservoir sample and then scaled up to yield the performance to be expected from field performance. Defa field was produced since 1968 with good oil flow rate reaching 200,000 BOPD but during the life of the field, the production decreased to 50,000 BOPD in 2001. So, this study was conducted to increase oil production by add some energy to the reservoir to increase average reservoir pressure and try to maintain it to initial pressure and to increase displacement and sweep efficiency. The water flooding design was implemented in sector model in the Defa field using five spots pattern. The study was performed by using Excel and Water Drive software to achieve a good water flooding design. When comparing the results obtained from two calculation methods, the minimum error was equal 0.03 percent and the maximum error was around 12 percent. So, the results were acceptable and the process was recommended to the Defa-field. Keywords: Water flooding; Software; Fractional Flow, Break through.

Application of dynamic material balance to evaluate oil wells in Buzurgan oil field

The Material Balance Equation is a crucial tool utilized in reservoir studies to evaluate fluids and rock properties at static pressures. The Flowing and Dynamic Material Balance methods offer a significant advantage by avoiding the requirement to shut down wells, as they use flowing pressure instead of static pressure under constant or variable flow rates. The concept of "Dynamic Material Balance" involves converting the bottom hole flowing pressure at any point at any given time to the average reservoir pressure at that point. This allows for the use of classical material balance calculations and the development of classical material balance plots. In this study, the Dynamic Material Balance and Agrawal Type Curve techniques were used to estimate average reservoir pressures, initial hydrocarbon in place, and ultimate oil recovery for a well in the Mishrif reservoir, the main reservoir in the Buzurgan oil field. Many wells in this field experience problems such as high-pressure decline or continuous water production, necessitating ongoing evaluation. While the Dynamic Material Balance method focuses on boundary-dominated flow data, the Agrawal-type curve technique analyzes data from both transient and boundary flow periods. Agarwal decline curves were constructed using relationships of pseudo pressure normalized production, material balance pseudo time, and dimensionless variables in well-test analysis. The results from both methods showed comparable results with an absolute percentage error of (0.738) %, (3.07) %, and 5.7% for oil-in-place, drainage area, and average reservoir pressure, respectively. This strong correlation between the Dynamic Material Balance and Type Curve results indicates their accuracy and reliability.

Geothermal Resource Assessment and Development Recommendations for the Huangliu Formation in the Central Depression of the Yinggehai Basin

As a renewable resource, geothermal energy plays an increasingly important role in global and regional energy structures. Influenced by regional tectonic activities, multi-stage thermal evolution, and continuous subsidence, the subsurface temperatures in the Yinggehai Basin has been consistently rising, resulting in the formation of multiple geothermal reservoirs. The Neogene Huangliu Formation, with its high geothermal gradients, suitable burial depths, considerable thickness, and wide distribution, provides excellent geological conditions for substantial geothermal resources. However, the thermal storage characteristics and geothermal resources of this formation have not been fully assessed, limiting their effective development. This study systematically collected and analyzed drilling, geological, and geophysical data to examine these reservoirs’ geometric structures, thermal properties, and physical characteristics. Further, we quantitatively evaluated the geothermal resource potential of the Huangliu Formation and its respective reservoirs through volumetric estimation and Monte Carlo simulations, pointing zones with high geothermal prospects and formulating targeted development strategies. The findings indicate: (1) The Yinggehai Basin exhibits an average geothermal gradient of 39.4 ± 4.7 °C/km and an average terrestrial heat flow of 77.4 ± 19.1 mW/m2, demonstrating a favorable geothermal background; (2) The central depression of the Huangliu Formation harbors considerable geothermal resource potential, with an average reservoir temperature of 140.9 °C, and a total geothermal resource quantified at approximately 2.75 × 1020 J, equivalent to 93.95 × 108 tec. Monte Carlo projections estimate the maximum potential resource at about 3.10 × 1020 J, approximately 105.9 ×108 tec. (3) Additionally, the R14 and R23 reservoirs have been identified as possessing the highest potential for geothermal resource development. The study also proposes a comprehensive utilization model that integrates offshore geothermal power generation with multiple applications. These findings provide a method for the evaluation of geothermal resources in the Yinggehai Basin and lay a foundation for the sustainable development of resources.

Enhancing economic sustainability in mature oil fields: Insights from the clustering approach to select candidate wells for extended shut-in

Fluctuations in oil prices adversely affect decision making situations in which performance forecasting must be combined with realistic price forecasts. In periods of significant price drops, companies may consider extended duration of well shut-ins (i.e. temporarily stopping oil production) for economic reasons. For example, prices during the early days of the Covid-19 pandemic forced operators to consider shutting in all or some of their active wells. In the case of partial shut-in, selection of candidate wells may evolve as a challenging decision problem considering the uncertainties involved. In this study, a mature oil field with a long (50+ years) production history with 170+ wells is considered. Reservoirs with similar conditions face many challenges related to economic sustainability such as frequent maintenance requirements and low production rates. We aimed to solve this decision-making problem through unsupervised machine learning. Average reservoir characteristics at well locations, well production performance statistics and well locations are used as potential features that could characterize similarities and differences among wells. While reservoir characteristics are measured at well locations for the purpose of describing the subsurface reservoir, well performance consists of volumetric rates and pressures, which are frequently measured during oil production. After a multivariate data analysis that explored correlations among parameters, clustering algorithms were used to identify groups of wells that are similar with respect to aforementioned features. Using the field’s reservoir simulation model, scenarios of shutting in different groups of wells were simulated. Forecasted reservoir performance for three years was used for economic evaluation that assumed an oil price drop to $30/bbl for 6, 12 or 18 months. Results of economic analysis were analyzed to identify which group(s) of wells should have been shut-in by also considering the sensitivity to different price levels. It was observed that wells can be characterized in the 3-cluster case as low, medium and high performance wells. Analyzing the forecasting scenarios showed that shutting in all or high- and medium-performance wells altogether results in better economic outcomes. The results were most sensitive to the number of active wells and the oil price during the high-price period. This study demonstrated the effectiveness of unsupervised machine learning in well classification for operational decision making purposes. Operating companies may use this approach for improved decision making to select wells for extended shut-in during low oil-price periods. This approach would lead to cost savings especially in mature fields with low-profit margins.

DEVELOPMENT OF AN ALGORITHM FOR CALCULATING COMPONENT COMPOSITION TO IMPROVE THE DEVELOPMENT OF OFFSHORE OIL FIELDS IN THE NORTH CASPIAN BASIN

The paper presents an algorithm to reconstruct the component composition of the mixture based on the results of production modeling in the black oil format and a fixed set of tables with the results of phase equilibrium calculations in a given pressure range. The approach is based on analyzing the ratio of flow rates for each phase and the ratio between average reservoir pressure and saturation pressure. The algorithm takes into account the possibility of oil degassing when saturation pressure decreases, as well as gas breakthrough of gas caps to the bottoms of producing wells.Implementation of the method is based on a unified thermodynamic model of multilayer reservoir, built on the principles of a single set of HC mixture components and uniform parameters of the equation of state on a set of fluid samples for all modeling stages: reservoir model, model of the gathering system and site facilities. In addition to steady-state flow calculations performed together with reservoir modeling, the unified model is planned to be used for dynamic flow calculations in the corresponding simulator (well start/stop), which will allow solving production problems in the process of operation of wells with complex completions.The conversion algorithm is automated using modern high-level tools: Python and data automation components from MS Excel, which eliminates the need for manual data input at all stages and makes it possible to obtain the estimated component composition of produced fluid for any set of wells and for any time step within the forecasting horizon.The obtained compositions are used to verify the reproduction of the main controlled parameters (oil density and gas oil ratio) and can be used for subsequent calculations of fluid transportation and treatment systems.The implemented algorithm has been tested for stability at different ratios of gas and oil flow rates by wells and meets the practical requirements of engineering calculations — the error of oil density is not higher than 2 % and gas factor is not higher than 10 %.

Constraining the radiocarbon reservoir age for the Southern Ocean using whale bones salvaged from early 20th century whaling stations

Radiocarbon dating is arguably the most common method for dating Quaternary deposits. However, accurate age assignments using radiocarbon dating are dependent on knowing the radiocarbon reservoir. For the coastal waters across Antarctica, the radiocarbon reservoirs show significant variation, ranging from 700 to 6000 years depending on the material dated and the period in question. In this study, we examine the radiocarbon reservoir age for the shallow waters of the Southern Ocean using 23 whale bones salvaged from commercial whaling operations on or near the Western Antarctic Peninsula between 1904 and 1916. The species origin of the bones had been identified previously as humpback, fin, or blue whales using sequences of mitochondrial (mt)DNA. We find an average reservoir age of 1050 ± 135 years for these 23 whale bones, with a <100-year difference in the reservoir age by species. A comparison between our results and other studies through the Holocene suggest that the Southern Ocean surface water radiocarbon reservoir age is of a similar magnitude across much of Antarctica and has not significantly changed for the last 14,000 years. Combining our new ages with existing data sets provides insight to the stability of the Southern Ocean marine radiocarbon reservoir age, enhancing our understanding of ocean ventilation and upwelling dynamics throughout the Holocene.

An improved neural operator framework for large-scale CO2 storage operations

Geologic carbon storage (GCS) is a practical solution to mitigate the impact of climate change and achieve net-zero carbon emissions. However, due to complex subsurface characteristics and operational constraints, GCS can potentially induce seismic events and leakage to groundwater resources. Moreover, predicting subsurface response in pressure and saturation changes during GCS requires high-fidelity models with high computational times. Machine learning (ML) offers a promising solution to alleviate these challenges. Yet, ML-driven approaches in subsurface physics face significant obstacles, such as the substantial computational resources required for training large-scale models and the accuracy requirement as a reliable surrogate model. To tackle these issues, we propose an improved neural operator (INO) that has improved a DeepONet architecture to handle a realistic reservoir model efficiently, with computational efficiency and high accuracy.Our proposed INO framework has three key benefits: precision, adaptability, and cost-efficiency. For precision, it achieves an average root mean square error (RMSE) of 0.05% (1.5 psi) compared to the average reservoir pressure (3,150 psi) and a RMSE value of 0.016 in void fraction for CO2 saturation among testing cases. Although it is sensitive to high-error areas with steep state variable gradients, proper domain decomposition, ensemble methods, and/or integrating domain-specific knowledge could improve this limitation. For adaptability, the INO framework can be trained with a subset of the computational domain during each backpropagation to achieve better training adaptability, even for problems with high-dimensional inputs (i.e., heterogeneous fields). For example, it can be trained with random subsampling of only 0.2% of the full domain but can predict pressure and saturation in any space and time within the entire domain. For cost efficiency, training procedures with a subset of the whole computational domain significantly improve computational time. For example, for 90 training cases with 1.73 million cells and 50-time steps, the overall training time was about 2.5 h using a single GPU. A trained INO model takes 1 s per evaluation over 1.73 million and 50 time stamps, much faster than a high-fidelity simulator. Overall, the proposed INO approach with these improved benefits will enable us to perform large-scale GCS applications, enhancing the potential of ML models in the subsurface and other multiphysics problems.

Climate Change Scenarios for Impact Assessment: Lower Zab River Basin (Iraq and Iran)

Selecting appropriate climate change scenarios is crucial, as it influences the outcomes of climate change impact studies. Several storylines could be used to investigate the sensitivity of water resource schemes to weather variability and improve policymakers’ adaptation strategies. This study proposes a comprehensive and generic methodology for assessing the future climate change impact on semi-arid and arid zones at the basin scale by comparing delta perturbation scenarios to the outcomes of seven collections of GCMs (general circulation models). The findings indicate that the two scenarios predicted nearly identical declines in average reservoir discharges over a monthly timescale. Consequently, their maximum values are almost similar. The projected decrease in the streamflow for the period 2080–2099 is approximately 48%—the same as the ratio from the delta perturbation scenario of Future16 (a 30% precipitation decrease and a 30% potential evapotranspiration increase). Furthermore, delta perturbation scenarios allow the impacts of model sensitivity to climate change to be clearly identified in relation to GCM scenarios. Delta perturbation scenarios allow for an extensive collection of possible climate changes at the regional scale. In addition, delta perturbation scenarios are simpler to create and use; therefore, they might complement GCM scenarios.

INFLUENCE OF NATURAL FACTORS OF SUPPORTING RESERVOIR PRESSURE AT THE LATE STAGE OF DEVELOPMENT OF GAS CONDENSATE FIELDS

The object of the research is natural factors that can affect both the maintenance of reservoir pressure in the process of developing gas condensate fields and the recovery of depleted deposits. Such factors include: waterflooding of deposits, subsidence of the surface, elasticity of rocks, water and gas, initial gradients of reservoir pressure in deposits, capillary forces. When studying the recovery of reserves in depleted gas condensate fields, it is necessary to take into account the influence of the above factors on the maintenance of reservoir pressure in order to identify the volumes of gas that flow from deep horizons (external sources). The paper shows the dynamics of waterflooding volumes and average reservoir pressures over the years. It is emphasized that waterflooding does not significantly affect the maintenance of reservoir pressure. Correlation dependencies of waterflooding volumes over time and the dependence of waterflooding volumes on reservoir pressure are given. An original system for calculating the volume of the water pressure system is proposed for the purpose of forecasting further waterflooding of deposits. The influences of all the above factors on the process of maintaining reservoir pressure are taken into account. It is shown that for the Shebelinsky GCF, all these factors do not significantly affect the recovery of reserves. The influence of capillary forces and evaporation of water in deposits on the development processes from the point of view of maintaining reservoir pressure at the late stage of GCF operation is studied.

The Dependence of Water and Gas Breakthrough on the Choice of Model Parameters in Naturally Fractured Reservoirs Using Sector and Full Reservoir Models

Assessing fractures in carbonate reservoirs is crucial due to their substantial impact on reservoir permeability. Understanding the characteristics of these fractures is vital for optimizing oil production. Additionally, extremely heterogeneous and anisotropic permeability distribution within the natural fractured reservoir is often caused by the complexity of a fracture network. Therefore, accurate reservoir modelling and simulation must be conducted in order to achieve ultimate recovery. In this paper, a sector model has been developed based on the studied example field, and its results are compared with the full reservoir model to find out the degree of resemblance between their outputs. The study area has four natural fracture compartments, with an average reservoir height of 95m and WOC and GOC depths of 685 m and 590 m, respectively. A dual-porosity and single-permeability modelling system was used to simulate the properties of the reservoir rock. This model was derived from the Petrel layercake model. A sensitivity analysis was also carried out to look into the relationships between field performance and the well. The outcomes of both models demonstrated that matrix permeability and fracture dimension had a significant impact on the early breakthrough of water and gas to comparable, huge extents. Other factors, such as aquifer size and WOC, show a moderate impact on water and gas breakthrough as well as final recovery.

Experimental analysis of acidizing in Weizhou X low permeability reservoir

AbstractAiming at the problem of increased water injection pressure and poor water injection effect during the water injection operation of Weizhou X offshore low permeability oil reservoir. The cause of clogging was clarified using cast thin section experiments, water quality compatibility experiments and reservoir sensitivity experiments, and corresponding deblocking agents were configured based on the experimental results. The experimental results show that Weizhou X oilfield has strong velocity sensitivity (damage rate 85.35%) and strong salt sensitivity (damage rate 63.02%), and there is a phenomenon of water quality incompatibility. Analysis shows that the excessive velocity of the injected water causes the core particles to fall off and the water quality is incompatible with the calcium carbonate precipitation to cause pore throat blockage as the fluid migrates to the small roar, which is the main reason for the increase in water injection pressure. Based on the analysis results, the acid solution formula was optimized and determined to be: 12% HCl + 0.5% HF + 3% CH3COOH + 0.5% C6H12N4. Indoor test results show that the acid has good clay swelling prevention and reservoir modification effects, and the average reservoir modification rate is 129.21%. The plug‐removing effect is remarkable and can be promoted in similar oil fields.

Synthesis of historical reservoir operations from 1980 to 2020 for the evaluation of reservoir representation in large-scale hydrologic models

Abstract. All the major river systems in the contiguous United States (CONUS) (and many in the world) are impacted by dams, yet reservoir operations remain difficult to quantify and model due to a lack of data. Reservoir operation data are often inaccessible or distributed across many local operating agencies, making the acquisition and processing of data records quite time-consuming. As a result, large-scale models often rely on simple parameterizations for assumed reservoir operations and have a very limited ability to evaluate how well these approaches match actual historical operations. Here, we use the first national dataset of historical reservoir operations in the CONUS domain, ResOpsUS, to analyze reservoir storage trends and operations in more than 600 major reservoirs across the US. Our results show clear regional differences in reservoir operations. In the eastern US, which is dominated by flood control storage, we see storage peaks in the winter months with sharper decreases in the operational range (i.e., the difference between monthly maximum and minimum storage) in the summer. In the more arid western US where storage is predominantly for irrigation, we find that storage peaks during the spring and summer with increases in the operational range during the summer months. The Lower Colorado region is an outlier because its seasonal storage dynamics more closely mirrored those of flood control basins, yet the region is classified as arid, and most reservoirs have irrigation uses. Consistent with previous studies, we show that average annual reservoir storage has decreased over the past 40 years, although our analyses show a much smaller decrease than previous work. The reservoir operation characterizations presented here can be used directly for development or evaluation of reservoir operations and their derived parameters in large-scale models. We also evaluate how well historical operations match common assumptions that are often applied in large-scale reservoir parameterizations. For example, we find that 100 dams have maximum storage values greater than the reported reservoir capacity from the Global Reservoirs and Dams database (GRanD). Finally, we show that operational ranges have been increasing over time in more arid regions and decreasing in more humid regions, pointing to the need for operating policies which are not solely based on static values.

Analysis of Field Data Using Microsoft Excel and MATLAB Software to Evaluate Reservoir and Well Damage

Reservoir formation damage is a drop in a well's productivity caused by a decrease in reservoir rock permeability. To tackle this issue and maximize well production, obtained pressure build-up time data at a steady production rate from a vertical producing oil WELL 20A, was analysed to establish the wellbore and reservoir characteristics. A numerical well test simulator (Matlab) is used to simulate damage in the area close to the wellbore, a Microsoft Excel sheet and an analytical approach to calculate the impact of wellbore and reservoir factors such as skin, wellbore storage, and average reservoir permeability. In order to determine whether the numerical well test simulator was successful at performing pressure transient analysis on observed data, the findings from the analytical solutions using Microsoft Excel Sheet and numerical well test simulator Matlab were compared. Comparable outcomes for the permeability and skin values were obtained from the build-up test data analysis generated; hence, the negative skin values for wells 20A acquired after the analysis suggest that the formation is not damaged. This indicate that well 20A is not a candidate for workover operations.

The Dependence of Water and Gas Breakthrough on the Choice of Model Parameters in Naturally Fractured Reservoirs Using Sector and Full Reservoir Models

Assessing fractures in carbonate reservoirs is crucial due to their substantial impact on reservoir permeability. Understanding the characteristics of these fractures is vital for optimizing oil production. Additionally, extremely heterogeneous and anisotropic permeability distribution within the natural fractured reservoir is often caused by the complexity of a fracture network. Therefore, accurate reservoir modelling and simulation must be conducted in order to achieve ultimate recovery. In this paper, a sector model has been developed based on the studied example field, and its results are compared with the full reservoir model to find out the degree of resemblance between their outputs. The study area has four natural fracture compartments, with an average reservoir height of 95m and WOC and GOC depths of 685 m and 590 m, respectively. A dual-porosity and single-permeability modelling system was used to simulate the properties of the reservoir rock. This model was derived from the Petrel layercake model. A sensitivity analysis was also carried out to look into the relationships between field performance and the well. The outcomes of both models demonstrated that matrix permeability and fracture dimension had a significant impact on the early breakthrough of water and gas to comparable, huge extents. Other factors, such as aquifer size and WOC, show a moderate impact on water and gas breakthrough as well as final recovery.

SOME ASPECTS OF THE GAS WELL TESTING PROCEDURES

The article discusses the basic concepts of designing and testing gas wells. The need to increase the selection of hydrocarbons determines the relevance of creating an information array of data on the reservoir and the fluids that saturate it. To collect information, the results of studies of the bottomhole zone of wells, its drainage zone and the interwell space of the reservoir are analyzed. According to the status, the studied wells are divided into operating and stopped for the period of research. According to the type of wells, production and injection wells are distinguished. In the first, the inflow curve is taken for various well operation modes (IPR). Secondly, the dependence of pressure change during shutdown of a working well (PBU) is analyzed. These studies can be carried out both in production and injection wells. To study well clusters and evaluate the interwell space, the methods of interference testing and the method of pulse studies are used. Information on hydrodynamic studies is provided. Note that the studies carried out in wells can be divided into two large groups. The first one is hydrodynamic studies (well test) which involves carrying out various tests to establish the characteristics of the rock that makes up the reservoir, as well as the properties of the fluid that saturates the porous medium. As a result of the studies, such parameters as permeability, porosity, average reservoir pressure, and degree of reservoir heterogeneity (presence of a screening fault, degree of fracturing, and layering) are determined. The second group includes studies that are carried out in wells in order to determine the volume of potential production, that is, productivity studies. It should be noted that the quality of the results is influenced by a large number of factors that must be taken into account in the process in order to increase the degree of reliability of the information obtained about the reservoir system. Thus, this article provides an analysis and the degree of influence of one or another parameter on the reliability of well test results. Keywords: flow rate, test duration, well, reservoir properties, skin factor, permeability, bot-tomhole pressure.

Identifying Average Reservoir Pressure in Multilayered Oil Wells Using Selective Inflow Performance (SIP) Method

The downhole flow profiles of the wells with single production tubes and mixed flow from more than one layer can be complicated, making it challenging to obtain the average pressure of each layer independently. Production log data can be used to monitor the impacts of pressure depletion over time and to determine average pressure with the use of Selective Inflow Performance (SIP). The SIP technique provides a method of determining the steady state of inflow relationship for each individual layer. The well flows at different stabilized surface rates, and for each rate, a production log is run throughout the producing interval to record both downhole flow rates and flowing pressure. PVT data can be used to convert measured in-situ rates to surface conditions. Different types of Inflow Performance Relationship (IPR) equations can be used for SIP interpretation, including the Straight-line method, Fetkovitch method, and Laminar Internal Turbulent (LIT) relations. Although the SIP method can be used for single-phase flow, the interpreter can restrict the IPR’s calculations to a particular phase. This research discusses the difficulties in estimating the average reservoir pressure in multilayered reservoir completed wells over their production life. The SIP technique has been applied to some producing wells in the south of Iraq, which are completed in multiple producing reservoirs previously tested with a formation tester to estimate reservoir pressure and other parameters. Two wells are taken in the south of Iraq region, Zubair Oil Field, one with cross flow between perforations and the other well with no cross flow. An average pressure is not calculated for layer A in Well-1, because there is no contribution rate. While the average pressure for Well-1, layer B is 3414.49 psia. Also, the average pressure for Well-2, layer H is not calculated because there is no rate contribution from this layer, and the maximum average pressure was calculated in layer G, which is about 2606.26 psia. It is also found that the presence of cross flow has no effect on SIP calculations.

KARAKTERISTIK GEOKIMIA AIR PANAS DAN ESTIMASI SUHU PERMUKAAN PANAS BUMI DI DAERAH SUOH KABUPATEN LAMPUNG BARAT PROVINSI LAMPUNG

Geochemical analysis is a method of geothermal exploration to determine the type of manifestation and estimate the temperature of the reservoir in the Suoh area and its surroundings. There are seven hot water sampling locations for physical observation and geochemical content tests, namely APS, APKSH, APKSC, APK1, APK2, APGS, and APBS. Geothermal manifestations in the Suoh area are on the path of the Sumatran fault system which is the result of a dextral-slip fault . If it is divided by segment, the Sumatran fault system in the study area is included in the Suoh segment, which in the Suoh segment, the fault line experiences a slight orientation and changes in tectonic activity, thus forming a transtension movement that works. The products of these forces result in movement apart and fractures forming a pull-apart basin opening . Based on the results of data processing using the geoindicator and water geothermometer methods, the results of plotting the Cl-SO4 -HCO3 diagram show that the seven hot water samples are the types of fluid types of chloride water and sulfuric acid water. Then the results of plotting the data using the Na-K-Mg diagram show that high Mg content indicates a process of dissolving ( leaching ) rocks near the surface and the results of water geothermometer calculations show that the average reservoir temperature ranges from 112-177 o C as a system temperature medium ( intermediate ). In the seven samples of hot water at the study site is a manifestation of geothermal fluid that comes directly from the reservoir.

Novel calculation method to predict gas–water two-phase production for the fractured tight-gas horizontal well

The prediction of production capacity in tight gas wells is greatly influenced by the characteristics of gas–water two-phase flow and the fracture network permeability parameters. However, traditional analytical models simplify the nonlinear problems of two-phase flow equations to a large extent, resulting in significant errors in dynamic analysis results. To address this issue, this study considers the characteristics of gas–water two-phase flow in the reservoir and fracture network, utilizes a trilinear flow model to characterize the effects of hydraulic fracturing, and takes into account the stress sensitivity of the reservoir and fractures. A predictive model for gas–water two-phase production in tight fractured horizontal wells is established. By combining the mass balance equation with the Newton–Raphson iteration method, the nonlinear parameters of the flow model are updated step by step using the average reservoir pressure. The accuracy of the model is validated through comparisons with results from commercial numerical simulation software and field case applications. The research results demonstrate that the established semi-analytical solution method efficiently handles the nonlinear two-phase flow problems, allowing for the rapid and accurate prediction of production capacity in tight gas wells. Water production significantly affects gas well productivity, and appropriate fracture network parameters are crucial for improving gas well productivity. The findings of this work could provide more clear understanding of the gas production performance from the fractured tight-gas horizontal well.