Recoverable Reserves Research Articles

Improving fluid identification in well logging using Continuous Wavelet Transform and Vision Transformers: An innovative approach

Well logging fluid prediction is one of the key steps in assessing oil and gas reserves. By analyzing downhole logging data, different types of fluids contained in underground rocks, such as crude oil, natural gas, and water, can be determined. This information is crucial for assessing the abundance and recoverable reserves of oil and gas resources and helps guide oil and gas exploration and development work. We have introduced a novel model called CWT (Continuous Wavelet Transform)-ViT (Vision Transformer). CWT can simultaneously provide frequency information at different scales, enabling the model to analyze downhole logging data more comprehensively and accurately at different scales. Underground rock structures often exhibit features at multiple scales, and CWT can effectively capture these features, aiding in better differentiation of different types of fluids. The ViT model utilizes the Transformer architecture, allowing for global attention over input sequences without being limited by sequence length. This enables the model to comprehensively understand the overall information of downhole logging data and extract richer features. For complex geological structures and fluid distributions in geological exploration, the global attention mechanism helps the model better grasp the overall situation, thereby improving the accuracy of fluid prediction. When we used the CWT-ViT method for well logging fluid prediction, we achieved a high accuracy rate of 97.50% in the first dataset, which further improved to 97.77% in the second dataset. These results demonstrate the significant robustness and efficiency of the CWT-ViT method in lithology prediction using well logging data. We also conducted blind well experiments, and our CWT-ViT model outperformed other models, achieving a blind well prediction accuracy of 97.36%. Therefore, the experiments indicate that the key to improving accuracy in well logging fluid prediction with CWT lies in its multiscale analysis capability, effectively capturing different fluid characteristic frequencies. Additionally, CWT enhances signal features and removes noise, increasing the precision of fluid identification. Finally, the integration with ViT further optimizes fluid prediction performance, making it outstanding in complex geological environments. The advantages of ViT in fluid prediction include its excellent sequence modeling capability, effective handling of long-distance dependencies, and enhanced ability to capture fluid characteristics in complex well logging data.

SOME FEATURES OF CONSTRUCTING DISPLACEMENT CHARACTERISTICS AND WATERING DYNAMICS

The term «displacement characteristic» (DCh) was first proposed by D. A. Efros in 1959 to indicate the dependence of the accumulated oil withdrawal on the accumulated liquid withdrawal. Subsequently, DChfound wide application in the analysis of oil field development. Many authors proposed various modifications of the DCh coordinates, but directactual measurements of development parameters were always used - annual, accumulated measurements of oil, liquid, water production, water cut, liquid, oil, and water flow rates. Characteristics of oil displacement are called graphical dependences of accumulated oil production on accumulated or current values of liquid or water production, constructed based on actual data. With the help of cold water, three tasks were solved: assessment of recoverable oil reserves, calculation of the technological effect of geological and technical measures, and calculation of technological development indicators. But the main condition for application was the immutability of the development system.Recently, dependences that use parameters such as selection from geological or recoverable oil reserves have come to be classified as chemical dependencies. These dependencies have nothing to do with DCh. Justification of geological and recoverable oil reserves is an independent task; moreover, with the help of chemical recovery, recoverable reserves are found under the existing development system. Against the background of such a confusion of concepts, the definition of the concept of «standard» chemicals is introduced, which has no real meaning for an oil development facility.The dynamics of water cut refers to the change in water cut over time, for example, depending on the time of development of reserves, geological or recoverable. The dynamics of watering in this case has nothing to do with the cold water.The dry period is of great importance when developing an oil field. With the same finaloil recovery, the longer the water-free period, the better the economic indicators.Using the Buckley-Leverett function todetermine water cut is only possible when the flow is two-phase, oil and water. It is impossible to determine the anhydrous period using the Buckley-Leverett function, since it does not exist, therefore, constructing the dynamics of water supply only based on this function is incorrect.When conducting laboratory experiments on core material, in which the heterogeneity compared to the formation is minimal and can be identified with a one-dimensional flow, the anhydrous period is significant and reaches from 0.74 to 0.94 units. of the total volume of displaced oil.For a single-layer field, where there is only one homogeneous layer, the heterogeneity is greater than for the core, but less than for a heterogeneous development object. We can talk about an analogue of a two-dimensional flow with some degree of convention.Considering that these are not laboratory studies, where measurements are carried out more accurately, but production ones, the low-water-cut period (up to 10 %) is 0.4 of the total oil production from wells with simultaneous commissioning of wells. If the wells were commissioned at different periods of time, as is always the case in fields, then the dynamics of water supply are completely different, and water supply begins earlier than when all wells are commissioned simultaneously.

Strategy for increasing the productivity of low-permeability reservoirs at the U-XIV horizon of the field in the Mangystau region

This article discusses the actual problems of developing residual reserves in mature fields with The article analyzes modern problems of development of residual oil reserves in mature fields with low reservoir properties. The field under study is characterized by multiple productive formations, tectonic disturbances and a variety of lithological characteristics in the intervals of the Jurassic productive strata. The field is characterized by structural complexity, heterogeneity of productive strata, various degrees of reserves development and a variety of residual balance reserves. The purpose of the work was to identify areas with low reservoir properties and assess the possibilities of optimizing their exploitation to improve the efficiency of oil production. To analyze current and predicted oil recovery factors (ORF), a calculation tool was developed using methods for evaluating displacement characteristics, including the Sazonov, Kambarov, Pirverdyan, Sipachev, Nazarov, Abyzbayev and Gaisin methods. These methods take into account various dependencies of the development parameters, which allows for more accurate prediction of oil recovery factors in the studied areas. The work also includes ranking of areas by residual recoverable reserves, production rates and projected growth of the oil recovery factor. Promising areas were identified for the construction of sector geological and hydrodynamic models (GHDMs), which allows for a more detailed assessment of opportunities to improve development efficiency. GHDMs were built and adapted for two selected areas with low reservoir properties, taking into account well parameters, development history, and reservoir filtration characteristics.

Research Progress on Injection Allocation and Regulation Methods of Injection Wells

Based on the research of the above problems, from the four aspects of calculating recoverable reserves, formulating reasonable well pattern forms, calculating the allocation amount and regulating measures, the corresponding calculation methods are summarized, and the principles, application steps, calculation formulas and conditions applicable to different reservoirs of each method are explained in detail. This paper provides a theoretical basis and foundation for further research on injection well matching and regulation methods, alleviating environmental pressure and achieving sustainable development.

Accounting for a capillary pressure jump in a saturated porous medium for a more correct calculation of hydrocarbon reserves

Relevance. The correct calculation of hydrocarbon reserves in various fields (oil, gas, gas condensate) is an important state task, because it allows you to properly organize field development in the future and ensure the rational use of natural resources of the state. In particular, the values of geological and recoverable reserves are assigned to a specific subsurface user and are recorded in departmental documents. Aim. To describe the effect associated with the calculations of the thermodynamic equilibrium of the mixture of hydrocarbons of the Karachaganak oil and gas condensate field at various formation depths with the capillary pressure jump taken into account. This makes it possible to clarify the value of the potential condensate-gas factor of reservoir gas and, as a result, to give a more accurate assessment of the geological reserves of hydrocarbon raw materials. Object. Analysis of the thermodynamic equilibrium of the hydrocarbon mixture of Karachaganak oil and gas condensate field, taking into account the capillary pressure jump, which takes place in a porous medium under reservoir conditions. Methods. Numerical modeling, analytical research. Results. Based on the previously developed methodology for calculating the phase equilibrium with the capillary pressure jump the correction of the potential condensate-gas factor of the formation gas of the Karachaganak oil and gas condensate field was carried out at various formation depths. The range of values of the condensate-gas factor difference for calculations both with and without capillary pressure jump was from 7,04 g/m3, with a condensate-gas factor value equal to 393 g/m3 for formation depth of 4000 m, to 64,47 g/m3, with a condensate-gas factor value equal to 547 g/m3 for formation depth of 4600 m. Based on the updated condensate-gas factor estimate, it is possible to clarify the condensate recovery coefficient during the development of a field without maintaining reservoir pressure or with partial maintaining reservoir pressure.

Prospects and current state of chemical EOR methods applied in Kazakhstan

At present, at almost all fields of the Republic of Kazakhstan the main technology of oil recovery enhancement is the traditional method of waterflooding of productive formations. Many oil and gas fields in Kazakhstan are at a late stage of development and are categorized as «mature» fields. In the global experience of mature field development, the key focus is on the application of enhanced oil recovery (EOR) techniques - chemical, thermal, gas and microbiological methods. This paper considers the application of chemical EOR at a number of Kazakh fields such as Zaburunye, North Buzachi, Kalamkas, East Moldabek. As the results of the pilot studies have shown, the most effective EOR here is the application of polymer flooding. It should also be noted that polymer flooding is successfully applied in Kazakhstan for high-viscosity oil fields such as North Buzachi (oil viscosity 316-417 mPa·s), East Moldabek (oil viscosity 246-377 mPa·s). In this case, water cut, smoothing of injectivity profile and, as a result, increase of oil production is achieved. Successful application of the technology largely depends on the parameters of physical and chemical impact at each stage - the volume of injection of gel-polymer composition, concentration of ingredients, the flow rate of filtered water, the presence and linear size of cracks, the permeability of pore channels and etc. Polymer flooding applied in Kazakhstan showed its technological and economic efficiency on the example of pilot tests, laboratory studies, which reduces water cut and increases oil production. Widespread use of EOR methods would allow increasing recoverable oil reserves by at least 5-10 %. Keywords: Enhanced Oil Recovery (EOR); gas Injection; hydrocarbon recovery methods; chemical EOR methods; thermal EOR methods; oil production; polymer flooding; oil recovery.

Analysis of possibilities for stabilizing hydrocarbon production depending on the stage of development

Of key importance for planning the sustainable development of territories is the potential for stable production of hydrocarbon reserves, which can be expressed by the time of its duration. In the practice of developing oil and gas fields, two methods are known to stabilize production: through geological and technological measures that increase the productivity of wells and by regulating their operating modes. The second method, on the contrary, involves limiting the growth of selections at the initial stage of development. Due to this, the further decline in production turns out to be slower. Accordingly, the need for geological and technological measures is also decreasing. To describe the quantitative characteristics of production stabilization in both cases, a mathematical apparatus has been developed, based on the equations of state of hydrocarbons, the laws of underground hydrodynamics, as well as the work of specialists in the field of analysis and forecasting of the production of hydrocarbon reserves. It has been established that the processes of development of recoverable reserves of both oil and gas are subject to the same laws, and therefore can be described by means of one generalizing equation. Based on the equation, formulas are derived for calculating the duration of a stable production period depending on both the efficiency of intensification technologies and the degree of capacity redundancy, as well as the availability of recoverable reserves and the degree of their production. Calculations of the duration of the stable production stage for specific geological and technological conditions are presented. Keywords: hydrocarbon production; geological and technological measures; operating mode; reserves development.

Nanofluid flooding as a method of enhancing oil recovery: mechanism, advantages

Relevance. The fact that with the help of modern methods of increasing oil recovery, it is possible to extract no more than 34 % of oil from the initial recoverable reserves. Therefore, modernization of technologies for tertiary impact on the reservoir as one of the possible ways of developing this area is required. It is possible to use nanoparticles in order to increase the oil recovery coefficient by displacing residual and hard-to-recover oil. Technologies with the use of nanoparticles have a number of significant advantages over the already traditional polymer, alkaline and surfactant flooding. Nanofluidic flooding allows increasing the oil recovery coefficient. The paper considers the mechanisms of action of nanoparticles contributing to oil recovery, the relationship of the effectiveness of flooding from the reservoir temperature, pH, water mineralization and wettability of the reservoir rock surface. These mechanisms are required for identifying limitations of the applicability of nanofluids, the possibility of their modification, in order to improve the properties and eliminate the disadvantages of nanofluid flooding. The effect of the chemical nature of nanoparticles, their size, surface charge, isoelectric point and concentration on rock, reservoir fluids and the efficiency of hydrocarbon extraction is considered in detail. Attention is also focused on the latest modern trends in the development of nanofluidic flooding technology. Aim. To conduct a comprehensive analysis of nanofluidic flooding as a method of increasing oil recovery. Objects. Chemical methods of enhancing oil recovery, nanofluidic flooding. Methods. Analysis of current publications on the research topic. Results. The factors influencing the effectiveness of the use of nanofluids as a method of increasing oil recovery and the mechanisms of the impact of nanoparticles on oil reservoirs are formed, promising directions for the development of nanoparticle technology are identified.

Bottom-up formulations for the multi-criteria decision analysis of oil and gas pipeline decommissioning in the North Sea: Brent field case study

Many Oil and Gas (O&G) fields in the North Sea have produced their economically recoverable reserves and have entered the decommissioning phase or are close to cessation of production. The subsequent O&G decommissioning process involves a range of stakeholders with specific interests and priorities. This range of inputs to the process highlights the necessity for the development of multi-criteria decision frameworks to help guide the decision-making process. This study presents bottom-up formulations for the economic, environmental, and safety risk criteria to support the multi-criteria decision analysis within the Comparative Assessment (CA) of O&G pipeline decommissioning projects in the North Sea. The approach adapts current guidelines in the O&G industry and considers a range of parameters to provide estimations for the costs, energy usage, greenhouse gas emissions, and safety risks. To verify the effectiveness of the proposed bottom-up formulations, the longest oil export pipeline in the Brent field, PL001/N0501 is selected as a case study. The numerical results revealed the consistency of the results obtained from the proposed approach with those reported in the technical documents by industry. In most cases, the formulations provide estimates with less than 10% differences for the costs, energy usage, emissions, and safety risks. Based on the proposed multi-criteria formulations, the study also presents the use of an immersive decision-making environment within a marine simulator system to help inform the decision-making process by stakeholders.

A 7th Law of Thermodynamics and its climate implications

Conversion of the ocean’s vertical thermal energy gradient to electricity via OTEC has been demonstrated at small scales over the past century. It represents one of the planet’s most significant (and growing) potential energy sources. As described here, all living organisms need to derive energy from their environment, which heretofore has been given scant serious consideration. A 7th Law of Thermodynamics would complete the suite of thermodynamic laws, unifying them into a universal solution for climate change. 90% of the warming heat going into the oceans is a reasonably recoverable reserve accessible with existing technology and existing economic circumstances. The stratified heat of the ocean’s tropical surface invites work production in accordance with the second law of thermodynamics with minimal environmental disruption. TG is the OTEC improvement that allows for producing two and a half times more energy. It is an endothermic energy reserve that obtains energy from the environment, thereby negating the production of waste heat. This likewise reduces the cost of energy and everything that relies on its consumption. The oceans have a wealth of dissolved minerals and metals that can be sourced for a renewable energy transition and for energy carriers that can deliver ocean-derived power to the land. At scale, 31,000 one-gigawatt (1-GW) TG plants are estimated to displace about 0.9 W/m2 of average global surface heat into deep water, from where, at a depth of 1000 m, unconverted heat diffuses back to the surface and is available for recycling.

Evaluation of the Pilot Test Effect of Steam Stimulation in Horizontal Wells of Sand Bodies 1-1308 in Bohai L Oilfield

In order to reduce the risk of large-scale thermal recovery of heavy oil in Bohai Oilfield, L Oilfield is selected to carry out horizontal well steam stimulation pilot tests. Previous studies have summarized the rationality of the injection parameters and initial production characteristics of this experiment, but the evaluation of its development effectiveness is still blank. Based on the study of the decline law of A23H well cold recovery using reservoir engineering methods, this article evaluates the initial production capacity, production increase effect, technical recoverable reserves, and throughput cycles of steam stimulation. The results show that the thermal recovery production of steam stimulation is three times that of cold recovery, which can significantly improve the production capacity of a single well. The initial daily oil production of two wells is 74m<sup>3</sup>/d and 90m<sup>3</sup>/d, respectively, which is 3.0 times and 3.6 times that of the initial production of cold recovery, exceeding the design level of the reservoir; The first round has the best yield increase effect, with an average daily oil increase of 31m<sup>3</sup>/d, and gradually decreasing thereafter. By the fifth round, it was only 13m<sup>3</sup>/d. In terms of yield increase multiples, each round can reach about 2 times; The technically recoverable reserves are 19.03 × 10<sup>4</sup>m<sup>3</sup>, requiring 8-9 rounds. Through this performance evaluation, we have strengthened our confidence in promoting the application of steam injection technology in Bohai Oilfield to achieve large-scale thermal recovery.

Novel methodology to couple decline curve analysis with CFD reservoir simulations for complex shale gas reservoirs

AbstractShale reservoirs are highly complex and are difficult to study using conventional reservoir simulation tools. This study introduces a novel methodology for estimating production from complex shale gas reservoirs by coupling decline curve analysis (DCA) with computational fluid dynamics (CFD) simulations. The proposed method uses exponential DCA to analyze production data from a dual porosity–permeability shale gas transport model. These complexities include fracture characteristics, geomechanical properties, nanopore confinement effects, and multiple flow mechanisms contributing to the total production performance. The shale gas transport model is validated through historical production data from Marcellus shale. The new methodology also tests fracture characteristics. It shows that increased porosity and permeability will increase the recoverable reserves but will have varying effects on the decline rate. The paper demonstrates the advantages of the proposed methodology over conventional reservoir simulation tools. It provides insights into the factors affecting shale gas production performance through the inclusion of the complexities of an unconventional shale gas reservoir. The paper provides a proof of concept on the particular reservoir of which the field data is provided—Barnett and Marcellus Shale.

Review about evaluation methods of recoverable reserves of deep water drive gas reservoirs in China

It has been widely accepted that China is one of the biggest natural gas consumers. Related to the imports of LNG, China stands in a very uncomfortable situation. Most domestic gas reservoirs fall within deep water drive gas reservoirs inordinately, which has entered the production depletion stage. Accurate estimation of SEC recoverable reserves of deep water drive gas reservoirs is of great significance for gas consumption planning and peak shaving. The existing calculation methods of recoverable reserves mainly consist of static methods and dynamic methods. In the early stage of exploration and development, the volumetric method has often been utilized to calculate the recoverable reserves. With the continuous development of gas reservoirs, the main methods for evaluation are dynamic methods, including the successive subtraction of production method, water drive curve method, prediction model method, attenuation curve method, improved virtual curve method, and material balance method for deep gas reservoirs.

Evaluation of Recoverable Hydrocarbon Reserves and Area Selection Methods for In Situ Conversion of Shale

It is well known that the existing horizontal-well-drilling and hydraulic fracturing technology used to achieve large-scale, cost-effective production from immature to low–moderate-maturity continental shale in China, where the organic matter mainly exists in solid form, is fairly ineffective. To overcome the obstacles, in situ conversion technology seems feasible, while implementing it in the target layer along with estimating the amount of expected recoverable hydrocarbon in such shale formations seems difficult. This is because there are no guidelines for choosing the most appropriate method and selecting relevant key parameters for this purpose. Hence, based on thermal simulation experiments during the in situ conversion of crude oil from the Triassic Chang 73 Formation in the Ordos Basin and the Cretaceous Nenjiang Formation in the Songliao Basin, this deficiency in knowledge was addressed. First, relationships between the in situ-converted total organic carbon (TOC) content and the vitrinite reflectance (Ro) of the shales and between the residual oil volume and the hydrocarbon yield were established. Second, the yields of residual oil and in situ-converted hydrocarbon were measured, revealing their sensitivity to fluid pressure and crude oil density. In addition, a model was proposed to estimate the amount of in situ-converted hydrocarbon based on TOC, hydrocarbon generation potential, Ro, residual oil volume, fluid pressure, and crude oil density. Finally, a method was established to determine key parameters of the final hydrocarbon yield from immature to low–moderate-maturity organic material during in situ conversion in shales. Following the procedure outlined in this paper, the estimated recoverable in situ-converted oil in the shales of the Nenjiang Formation in the Songliao Basin was estimated to be approximately 292 × 108 tons, along with 18.5 × 1012 cubic meters of natural gas, in an area of approximately 8 × 104 square kilometers. Collectively, the method developed in this study is independent of the organic matter type and other geological and/or petrophysical properties of the formation and can be applied to other areas globally where there are no available in situ conversion thermal simulation experimental data.

Design of corresponding fracturing parameters based on thin sand reservoir characteristics

Abstract China’s onshore oil fields have entered the late stage of development, while the reserves of thin-poor layers account for a large proportion of the remaining recoverable reserves. The development of thin-poor reservoirs has become an important potential for tapping potential. In this paper, the numerical simulation method is used to optimize the crack radius corresponding to the fracturing of the thin-poll injection-production system. The optimization results show that the fractured radius of the well has a greater impact on the final cumulative oil production and recovery when the fractured radius does not break the permeability boundary for a thin reservoir with a fracture penetration ratio of water and oil wells between 35% and 45%. when the oil well is in the high permeability area and the water well is in the low permeability area, the fractured radius of the well and the surrounding area of the oil well are used. The situation has a greater impact on the final oil production.

A New Evaluation Method of Recoverable Reserves and Its Application in Carbonate Gas Reservoirs

A New Evaluation Method of Recoverable Reserves and Its Application in Carbonate Gas Reservoirs

EXPLORING THE POTENTIAL FOR OPERATIONAL OVERSIGHT OF REMAINING RECOVERABLE RESERVES THROUGHOUT VARIOUS PHASES OF OIL PRODUCTION FACILITY DEVELOPMENT

Assessing oil recovery rates through geological and hydrodynamic modeling incurs significant financial and time investments. Consequently, recalculations of recoverable hydrocarbon reserves occur infrequently, leading to potential discrepancies between approved factors and actual conditions. To ensure accuracy in assessing residual recoverable reserves, it's crucial to promptly monitor the validity of oil recovery factors, especially concerning their achievability within specific timeframes. This article examines the practice of annually assessing geological and economic reserves according to international standards. Operational monitoring methods include analog-statistical techniques, displacement characteristics, and production decline rate analysis, each reliant on initial data quality and production object development stages. The effectiveness of these methods is illustrated through specific examples. Analog-statistical dependencies, tailored to operational facilities' geological indicators, prove most effective for early-stage development. In advanced stages, methods based on displacement characteristics and production decline rates gain reliability, factoring in economic development profitability limits. Statistical dependencies incorporating technological indicators can enhance control measures. Integrating diverse methodological approaches ensures a more dependable assessment of production object residual recoverable reserves. When determining residual recoverable reserves and designing the development of oil fields, the main characteristic that determines the reliability of forecast calculations is the accuracy of estimating the oil recovery factor. The value of the oil recovery factor characterizes the share of initial recoverable reserves that can be extracted from the subsoil from the initial geological reserves when developing a deposit using modern proven technology and production techniques to the limit of economic profitability while complying with the requirements of subsoil and environmental protection. The most common method for estimating the oil recovery factor is digital geological-hydrodynamic modeling, in which the processes occurring during the development of oil deposits are simulated using software. This method has been introduced in the Russian oil industry since the mid-90s. XX century, recommended for use by current regulations [1]. Based on digital geological and hydrodynamic modeling, various options for the development of oil deposits are calculated, differing in the number of production and injection wells, the rate of reserve withdrawal, etc. Examples of the effective use of digital geological and hydrodynamic modeling in designing the development of oil fields are given in works [2–4], in including for the territory of the Perm region [5–10]. The most economically feasible option for field development is approved by the authorized government bodies, and each production facility is characterized by a design oil recovery factor. There is no doubt that the construction of digital geological and hydrodynamic modeling in the presence of standard geological and technological data is the most reliable way to determine the oil recovery factor. However, this method requires very large financial and time costs, which leads to significant time intervals between calculations of the Oil Recovery Factor, which in most cases exceed 10 years. As a result, over time, the approved Oil Recovery Factor may significantly lose relevance both due to the discrepancy between the design development indicators and the actual ones, and due to changes in the economic conditions of development. Taking this into account, it is extremely important for production facilities to quickly monitor the validity of the Oil Recovery Factor, including its objective achievability in a specific time frame. Keywords: Remaining recoverable reserves, efficiency of oil extraction, operational facility, design of oil field development, evaluation of geological and economic reserves, displacement patterns, decline in oil production rate.

Study on the Division of Remaining Recoverable Reserves Abundance in Specific Reservoirs

Study on the Division of Remaining Recoverable Reserves Abundance in Specific Reservoirs

Solutions to Complex Well-Testing Challenges Aid Offshore Black Sea Gasfield Development

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 215123, “Frontiering Ultradeep Water Gas Field Development, Offshore Black Sea, Turkey: Solutions to Complex Well-Testing Challenges and Proving Production Potential,” by Coşan Ayan, SPE, Suat Aktepe, and Koscal Cig, Turkish Petroleum, et al. The paper has not been peer reviewed. _ Increasing demand for reliable energy resources has led to an increased exploration activity for untapped hydrocarbon resources in deep water. The recently discovered, fast-tracked Sakarya offshore natural gasfield development is a prime example. This paper describes dynamic reservoir characterization considerations, challenges, and engineering solutions to derisk field-development decisions, confirmed by a well-testing campaign in a complex setting with no tolerance for failure. Sakarya Field The Sakarya field is approximately 170 km north of the Turkish coast in the Black Sea at 2117 m (Fig. 1). The natural gas field was discovered in August 2020 and is estimated to have potential natural gas reserves of 11 Tcf of lean gas, making it the largest gas reserve discovered in the Turkish Exclusive Economic Zone as well as the Black Sea. In October 2020, a second discovery was made in the lower sections of Tuna 1, which increased the potential recoverable reserve estimate to 14.3 Tcf of lean gas. The discovery was found at the deeper part of the well, where an additional 30 m of gas pay was encountered in the sandstone reservoir of the Late Miocene. Further, the drilling of the exploratory well Amasra 1, 40 km north of the Sakarya field, led to the discovery of 4.7 Tcf of gas in June 2021, and increased the potential recoverable cumulative natural gas reserves to 19 Tcf. The first gas production from the Sakarya gas field began in 2023 into the Turkish grid from the completed wells of the first phase of the project. To accelerate the time to first gas production, it was deemed necessary to flow-test the reservoirs to acquire critical reservoir information, assess production potential and completions efficiency, and reduce the number of wells. This was achieved by drilling and testing several appraisal wells with multiple target intervals that will be used later as producers. Well-Completion Strategy Affecting Well-Test Program Formation-failure studies and wireline formation testing data have shown that these weak reservoirs are prone to sand production. As a result, downhole sand-exclusion completions are necessary. Gas permeabilities are good, with core-measured air permeabilities in the range of 1–1000 md. The reservoir pressure varies from 4,200 to 5,800 psi, depending on depth. Reservoir temperatures are relatively low, in the range of 25–60°C. Lower Completion Installation Sequences. After drilling, the main section was completed with 9⅞-in. 62.8-lbm/ft production casing. The selected interval from openhole logs and formation test results was perforated and overbalanced by individual runs of a tubing-conveyed perforation (TCP) system. On the second run, sump packers with direct wrap screens across the interval were installed and gravel was pumped. After the lower completion was in place and the drillstem test (DST) had been conducted, another part of the lower completion across the upper interval was installed and flow-tested. After completing all DST well tests, the well was suspended with the lower completion system in place, ready for installation of the upper completion with intelligent flow-control valves and permanent gauges.

Application of Machine Learning for Productivity Prediction in Tight Gas Reservoirs

Accurate well productivity prediction plays a significant role in formulating reservoir development plans. However, traditional well productivity prediction methods lack accuracy in tight gas reservoirs; therefore, this paper quantitatively evaluates the correlations between absolute open flow and the critical parameters for Linxing tight gas reservoirs through statistical analysis. Dominant control factors are obtained by considering reservoir engineering theories, and a novel machine learning-based well productivity prediction method is proposed for tight gas reservoirs. The adaptability of the productivity prediction model is assessed through machine learning and field data analysis. Combined with the typical decline curve analysis, the estimated ultimate recovery (EUR) of a single well in the tight gas reservoir is forecasted in an appropriate range. The results of the study include 10 parameters (such as gas saturation) identified as the dominant controlling factors for well productivity and geological factors that impact the productivity in this area compared to fracturing parameters. According to the prediction results of the three models, the R2 of Support Vector Regression (SVR), Back Propagation (BP), and Random Forest (RF) models are 0.72, 0.87, and 0.91, respectively. The results indicate that RF has a more accurate prediction. In addition, the RF model is more suitable for medium and high-production wells based on the actual field data. Based on this model, it is verified that the productivity of low-producing wells is affected by water production. This study confirms the model’s reliability and application value by predicting recoverable reserves for a single well.