Carbonate Gas Reservoir Research Articles

Production Behavior Evaluation on Inclined Well in Commingled Carbonate Gas Reservoir With Multiple Heterogeneous Layers Without Crossflow

Abstract To estimate production behaviors of inclined well in multilayer heterogeneous carbonate gas reservoir, two semi-analytical models for different formation distribution patterns are proposed, which are named as model I and model II. For model I, the inner region of each layer is fractured-vuggy porous medium, while the outer region only contains matrix. For model II, the inner and outer regions are consisted of matrix and fractured-vuggy porous mediums, respectively. To solve the model, Laplace transformation, Fourier transformation and inversion, Duhamel convolution, and Stehfest numerical inverse are applied. The validities of these models are verified through the comparisons with the published datum, which include well bottom-hole pressure (BHP) and gas production rate of individual layer for vertical and inclined wells in multilayer homogenous gas reservoir. Furthermore, by matching the well BHP data collected from a field case, the applicability of model is validated. The influences of prevailing factors, such as the radius ratio between inner and outer regions, horizontal–vertical permeability ratio, and inclination angle, on production behaviors are analyzed. The results show that influenced by the diverse formation distribution patterns, the variation of radius ratio between inner and outer regions has opposite effect on the well BHP for models I and II. Formation anisotropy and inclination angle have minimal effects on the well BHP of model I, but have significant impacts on model II. To keep the well BHP with a relatively high value, for model I and model II, the penetrate inclination angles should be greater than 50 deg and 55 deg, respectively.

Analytical well-test model for hydraulicly fractured wells with multiwell interference in double porosity gas reservoirs

Interference resulting from infill wells in multiwell systems becomes a common issue in interpreting well tests data from hydraulicly fractured wells in tight carbonate gas reservoirs. Current single-well pressure transient approaches may falsely interpret well interferences as the composite reservoir or boundary effects, leading to significant errors in reservoir parameter estimation. Additionally, the most semi-analytical and numerical solutions used for fractured wells are computationally demanding and inconvenient to use. This work presents a novel and simple analytical well-test model for hydraulicly fractured wells with multiwell interference in double porosity gas reservoirs with significantly less computational time and effort than the existing methods. The analytical solution for a hydraulically fractured well with finite conductivity fracture in a multiwell system with well interference is presented based on the superposition principle, the early-time approximate solutions of trilinear flow and the infinite-conductivity fracture model. A systematic verification is conducted to ensure the validity of the presented solution. The solution is valid when the dimensionless fracture conductivity is greater than 1 (FcD>1) with ∼1% error in pressure and derivative. Furthermore, we offer a criterion of identifying well interference using the pressure derivative of the late-time approximation of the proposed analytical solution. Finally, a case study is conducted in the Sichuan Basin, indicating the proposed solution's applicability.

Geological Characteristics and Development Techniques for Carbonate Gas Reservoir with Weathering Crust Formation in Ordos Basin, China

The carbonate gas reservoir is one of the most important gas formation types; it comprises a large proportion of the global gas reserves and the annual gas production rate. However, a carbonate reservoir with weathering crust formation is rare, and it is of significant interest to illustrate the geological characteristics of this kind of formation and present the emerging problems and solution measures that have arisen during its exploitation. Therefore, in this research, a typical carbonate gas reservoir with weathering crust formation that is located in Ordos Basin, China, was comprehensively studied. In terms of formation geology, for this reservoir, the distribution area is broad and there are multiple gas-bearing layers with low abundance and strong heterogeneity, which have led to large differences in gas well production performance. Some areas in this reservoir are rich in water, which seriously affects gas well production. Regarding production dynamics, the main production areas in this gas reservoir have been stable on a scale of 5.5 billion cubic meters for more than a decade, and the peripheral area has been continually evaluated to improve production capacity. Nevertheless, after decades of exploration and development, the main areas of this reservoir are faced with several problems, including an unclear groove distribution, an unbalanced exploitation degree, low formation pressure, and increases in intermittent gas wells. To deal with these problems and maintain the stability of gas reservoir production, a series of technologies have been presented. In addition, several strategies have been proposed to solve issues that have emerged during the exploration and exploitation of peripheral reservoir areas, such as low-quality formation, unclear ancient land and complex formation-water distribution. These development measures employed in the carbonate gas reservoir with weathering crust formation in the Ordos Basin will surely provide some guidance for the efficient exploitation of similar reservoirs in other basins all over the world.

A novel approach by integrating the core derived FZI and well logging data into artificial neural network model for improved permeability prediction in a heterogeneous gas reservoir

Predicting and extrapolating the permeability between wells to obtain the 3D distribution for the geological model, is a crucial and challenging task in reservoir simulation. Permeability is influenced by both digenetic characteristics and depositional factors like sorting and grain size. Hence, a reliable model should consider these characteristics for prediction of permeability. Grouping the rocks into different hydraulic flow units (HFU) or discrete rock types (DRT), improves the identity of the reservoir characteristics and provide a more accurate permeability prediction. Multi variable regression models and Artificial Neural Networks (ANN) were applied in this study to correlate core permeability and porosity with well logs to predict permeability logs. It was observed that the accuracy of the models diminished in heterogeneous reservoirs, where there is a wide permeability distribution.In this study, we are presenting a novel approach to predict permeability in heterogeneous oil and gas reservoirs. In this method the core permeability and porosity data are categorized using the concept of DRT and the probability density functions are used to investigate the relationships between the logs and DRT groups. The ANN model is applied to correlate the core derived flow zone indicator (FZI) with wire-line logging data with a single key well to predict K-logs. In this approach one single well, which contains all DRT groups is considered as a key well to develop and train the ANN model. It was observed that ANN model exhibits better prediction performance in heterogeneous reservoirs when it is developed and trained on single well data containing all DRT groups. This approach can capture heterogeneity in the reservoirs where it has been applied successfully to predict permeability in an actual heterogeneous carbonate gas reservoir.

Preventing sour gas kicks during workover of natural gas wells from deep carbonate reservoirs with anti‐hydrogen sulfide fuzzy‐ball kill fluid

AbstractWorkover of natural gas wells in deep carbonate gas reservoirs (DCRs) is facing multiple challenges such as fluid leakage, high temperature, and hydrogen sulfide (H2S) gas kick. Hence, well‐killing fluids with satisfactory plugging ability, high‐temperature tolerance, and anti‐H2S ability are necessary. In this study, we developed a multifunctional anti‐hydrogen sulfide fuzzy‐ball kill fluid (AFKF) for preventing sour gas kicks in DCRs. The performance of the AFKF was optimized and analyzed via experiments and verified through a case study application. The results showed that the fuzzy‐ball structures in the AFKFs demonstrated good stability under extreme H2S aging. The rate of change of certain critical rheological parameters such as apparent viscosity, dynamic plastic ratio, and density of AFKFs before and after hot rolling were no more than 5%. After plugging the fractures with the AFKFs at temperatures between 110°C and 150°C, the inlet driving pressure of the fractures increased from 20.73°C to 21.07 MPa, and no fluid loss was observed at the core outlet after a secondary displacement of formation water. The permeability recovery rate was greater than 90%. Application of AFKF in well DW‐2 showed that the shut‐in pressure rose to 24.6 MPa with no trace of H2S gas at the wellhead after 4 days. The investigation of the H2S mitigation mechanisms revealed that the plugging of the seepage channels by AFKFs forms interconnected bonds that improve the mechanical properties of the reservoir. Additionally, AFKFs absorb H2S gases by protonation and dissociation reactions which convert the hazardous gas into an aqueous solution of sulfide ions (S2−). The proposed AFKF has proven to be effective means of mitigating H2S in DCRs, and minimize the negative impacts of environmental polution, health risks, and equipment corrosion.

Experimental analysis and deliverability calculation of abnormally pressured carbonate gas reservoir considering stress sensitivity

The stress sensitivity of abnormally pressured carbonate gas reservoirs is of great complexity and exerts much influence on gas well deliverability calculation. Fifty core samples from the AD Gas Reservoirs were selected in the experiment to study the effect of abnormally high pressure and fracture on the stress sensitivity of carbonate gas reservoir. The results show that the permeability decline mainly occurs in the abnormally high-pressure stage and is rather small in normal pressure stage. The existence of the fracture could substantially enhance the stress sensitivity. The higher fracture density could induce the stronger stress sensitivity. Furthermore, a mathematical model with the consideration of the variable permeability modulus was established to calculate gas well deliverability in the abnormally pressured carbonate gas reservoir with developed natural fractures. It is revealed that previous method assuming a fixed permeability modulus would lead to an overestimation of the real stress sensitivity and thus underestimating the absolute open flow of the gas well.

Water Invasion Mode of Carbonate Gas Reservoirs Controlled by Edge Water: Three Invasion Modes

Water Invasion Mode of Carbonate Gas Reservoirs Controlled by Edge Water: Three Invasion Modes

Natural gas development prospect in Changqing gas province of the Ordos Basin

At present, natural gas accounts for a low proportion in China's primary energy consumption structure and is highly dependent on foreign sources. Changqing gas province of the Ordos Basin where PetroChina Changqing Oilfield Company (referred to as Changqing Oilfield) is located is one of China's four major natural gas production bases. It bears the important responsibility for ensuring people's livelihood and promoting the healthy development of society economy. In recent years, Changqing Oilfield actively implements national instructive spirit on vigorously promoting domestic oil and gas exploration and development strength and formulates the secondary acceleration development strategies. Its annual natural gas production in 2020 reaches 448.5 × 108 m3 and oil and gas equivalent exceeds 6000 × 104 t, tamping its important position of “Western Daqing” in this industry. In order to further promote the continuous stable production and realize the goal of quality and efficiency improvement in Changqing gas province, this paper analyzes the situations and challenges of natural gas development in this gas province, prepares the development technological countermeasures and forecast the natural gas development prospect. And the following research results are obtained. First, the natural gas exploration and development in Changqing gas province is divided into four stages and the main technologies for the development of low-permeability carbonate gas reservoir, low-permeability sandstone gas reservoir and tight sandstone gas reservoir are formed. Second, the natural gas development in Changqing gas province faces six challenges, such as low reserve production degree, sharp decline of production rates and complex distribution of remaining undeveloped reserves of developed gas fields. And twenty-six development technological countermeasures are put forward correspondingly, such as well pattern thickening, extension and reserve increase, secondary production layer potential tapping and fine gas well management. Third, the development direction and goal of natural gas development in Changqing gas province is to pay equal attention to the stable production of old gas fields and the production increase of new areas and carry out conventional gas and unconventional gas research simultaneously. In conclusion, the annual natural gas production of Changqing gas province will maintain a sound momentum of steady growth and will exceed 500 × 108 m3 at the end of the 14th Five-Year Plan and maintain at a stable level for a long term, which is conducive to the optimization of domestic energy consumption structure and realization of “carbon peak and carbon neutrality”.

Development prospect of natural gas industry in the Sichuan Basin in the next decade

The Sichuan Basin is the earliest natural gas discovery and utilization area in the world, where China's modern natural gas industry started. Through nearly 7 decades of development, a natural gas industrial system with complete upstream, midstream and downstream industry chain has been established, and its natural gas production has been among the top in China for half a century. And it has played an important role in the process of improving the primary energy consumption structure and constructing a “beautiful China”. The evaluation result of national oil and gas resources in the 13th Five-Year Plan shows that the natural gas resource extent in the Sichuan Basin is 39.94 × 1012 m3, ranking the first in petroliferous basins of China. In addition, the proven rate of natural gas resource is only 15% and it is still in the early and middles stages of exploration. Therefore, the Sichuan Basin has great potential in natural gas exploration and development. The natural gas production in the Sichuan Basin in 2020 is 565 × 108 m3 (including all production enterprises of PetroChina and Sinopec in the Sichuan Basin), taking the first place in China major gas producing areas. Over the next decade, the China puts forward new development concepts from the perspective of development circumstances. The construction of Chengdu–Chongqing economic circle will be promoted and a national natural gas strategic production base with yearly gas production of 1000 × 108 m3 will be built up in the Sichuan Basin, which marks a new golden development age of natural gas industry in the Sichuan Basin. From the perspective of development potential, deep and ultra-deep marine carbonate gas reservoirs, deep shale gas and continental tight sandstone gas will be the key exploration and development fields to search for giant gas fields in the Sichuan Basin. It is recommended to strengthen core technology researches according to the thoughts of “coordinated development of marine and continental, conventional and unconventional, structural and lithologic” and relying on theoretical and technological progress. In the future, it will enter a booming development period when the quality of natural gas resources will be continuously improved and the production rate will be increased continuously. In the meantime, take advantage of the opportunities of prosperity development to break through the development bottleneck of increasingly complex work objects, incomplete pipeline network system and insufficient high end and high additional value industries. Under the situation of normalized low oil price, construct a new-type industrial system with the coordinative development of natural gas production, transportation, storage and marketing and the innovation and efficiency improvement in the whole industrial chain. It is predictable that the natural gas industry in the Sichuan Basin will start in a new peak growth period and a high-quality development period in the next decade, and its yearly natural gas production will exceed 1000 × 108 m3, and the yearly natural gas production of PetroChina Southwest Oil & Gasfield Company will reach 800 × 108 m3 in 2030. Obviously, the Sichuan Basin will be a world-class natural gas production and supply base.

Production Performance Analysis for Deviated Wells in Carbonate Gas Reservoirs With Multiple Heterogeneous layers

Deviated wells are used to improve the performance of carbonate reservoirs with multiple heterogeneous layers and penetrate the “sweet spot” of each layer, which is full of fractures and vugs. It is difficult to consider in-layer and inter-layer heterogeneities simultaneously, and predict the production performance for these wells accurately. Therefore, a semi-analytical model to analyze the production performance of deviated wells in a multilayer heterogeneous stress-sensitive carbonate gas reservoir is proposed. For each layer, the inner region is a fractured-vuggy porous medium, while the outer region is merely a tight formation with matrix and formation properties, and penetrated inclination angles may be distinct. Pseudo-time/pressure factors are introduced to consider fracture stress sensitivity. Through the application of Laplace transformation, Fourier transform and inverse, Duhamel convolution, and Stehfest numerical inversion, the presented model is solved. The validity of this model is verified through comparison with single-layer composite formation with different porous mediums and vertical well in a multilayer carbonate gas reservoir. Moreover, by matching bottom-hole pressure data collected from a slanted well in the Anyue gas field, the applicability of this model is validated. A synthetic case, which has two composite formations, the first (upper) layer is more permeable than the second (lower) layer, is used to study the variations of inner region radius, fracture/matrix permeability, and inclination angles on production behaviors. The results show the properties of the first layer determine well bottom-hole pressure, whereas the rise of permeability, inner region radius and penetrated angle for the second layer can improve the gas recovery of this layer. In practice, to maintain well bottom-hole pressure with a relatively high level and enhance gas recovery of the tight layer, the inclination angle should be larger than 60° for each layer, and be increased to as large as possible. The findings of this study can help for a better understanding of the production behaviors of deviated wells in multilayer heterogenous reservoirs and could provide some guidance for the design of well trajectory.

Research on Well Area Connectivity of Carbonate Gas Reservoir in Eastern Sichuan Basin—A Case Study of Wubaiti Block

Carbonate gas reservoirs in the eastern Sichuan Basin are featured by low matrix permeability and well-developed fractures, caves, and faults, which result in complicated fluid flow and connectivity. The Wubaiti Carboniferous gas reservoir is an earlier developed block in Eastern Sichuan with a development history of 27 years. The geological features, e.g., block structure and fault development, have been extensively studied, but a few studies address the connection relationship and gas–water interface of the DT 2 well area in the north. To solve this problem, this paper proposes a reserve simulation method based on the conventional connectivity analysis, which calculates the reserves of different gas–water interfaces in the well area. Combined with production performance analysis, the well-controlled reserves and drainage area were also determined. The analysis verifies the connectivity between wells. Integrating with interference testing, fluid properties, and seismic and geological data, the connection relationship between well areas is further clarified. The results show that the northern water bodies of the DT 2 well area consist of two independent and disconnected water bodies. There is a blocking zone between the DT 2 and DT 3 and DT 4 wells, which causes the disconnection of water bodies but the connection of gas. The results also indicate that the eastern water body of the main area and the eastern water body of the DT 2 well area are part of a uniform water body with a uniform gas–water interface. The research method is significant for the connectivity research of similar gas reservoirs.

Graded Control Technology of Oil Stability and Water Control in Fracture-Pore Carbonate Reservoirs

In view of the prominent problems of extremely strong heterogeneity, fracture development of different scales, and serious rapid water channelling in the process of water injection development in fracture-pore carbonate reservoirs, a comprehensive treatment method of oil stabilizing and water controlling is proposed, which includes fracture classification control, combination of adjustment and plugging, and wettability change. Based on the static and dynamic test data, the characteristics of reservoir fracture development and fracture scales are described in detail. By means of reservoir engineering and numerical simulation, the water flooding rule under different grade fracture reservoir conditions is studied, the influence of different levels of fractures on water injection development is evaluated, and the improvement effect of different control methods on water drive sweep is demonstrated. Research shows that a large amount of remaining oil trapped in pores is affected by fracture water channelling, which makes it difficult to use effectively. The water flooding sweep characteristics of reservoirs with different scales of fractures are quite different, and large-scale fractures are the main reason for ineffective water injection. The hierarchical control techniques of plugging large-scale fractures, intervening and adjusting small- and medium-scale fractures, and changing the wettability of microscale pore media can significantly extend the water flooding spread range and effectively improve oil well production. The research results have been applied in the field and achieved good results. This technology can provide theoretical guidance and a technical basis for the comprehensive treatment of oil stabilization and water control in fractured-porous carbonate oil and gas reservoirs.

Two-phase Flow Model and Productivity Evaluation of Gas and Water for Dual-Medium Carbonate Gas Reservoirs

Fluid flow in the dual-medium carbonate gas reservoir is characterized by stress sensitivity and non-Darcy flow effect. In order to accurately describe the unsteady flow of gas and water in the dual-medium gas reservoir, a two-phase flow model of gas and water is built. First, reservoir space and fluid flow characteristics of carbonate gas reservoirs are investigated, and the flow model that considers both the stress sensitivity and non-Darcy flow is built based on the fundamental flow theory, after fully investigating the reservoir space and fluid flow characteristics of carbonate gas reservoirs. Then, the perturbation theory is introduced, and the model is solved in the Laplace space, after which the obtained Laplace space analytical solution is converted into the real-space solution. Finally, the productivity evaluation model for the dual-medium gas reservoir with the gas-water two-phase flow is built, based on the flowing material balance method and Newton iteration. The presented productivity evaluation model is applied to analyze the effects of stress sensitivity and non-Darcy flow on the two-phase flow model of gas and water for the dual-medium gas reservoir and the reservoir productivity. The results indicate that a higher stress sensitivity coefficient is demonstrated to indicate higher stress sensitivity and accelerated production decline of the reservoir, while a lower non-Darcy flow effect coefficient represents a stronger non-Darcy effect and boosted drop of initial production of the reservoir. Hence, it is not reasonable to neglect the effects of stress sensitivity and non-Darcy flow during the evaluation of the productivity of a dual-medium carbonate gas reservoir. The model presented in this research provides important references for improving the recovery performance of dual-medium gas reservoirs.

Multiscale pore structure characterization of an ultra-deep carbonate gas reservoir

The pore structures of shallow and mid-deep carbonate gas reservoirs have been well explored. Totally different from these reservoirs, however, the pore structure of a target ultra-deep carbonate gas reservoir, the Qixia Reservoir in the Shuangyushi play is still unknown. Affected by tectonic movement and deep hydrothermal transformation, the lithology of this target reservoir has significantly changed and it has developed different scales of pores and fractures. Thus, a multiscale micro-CT (computed tomography) method is needed to combine different scales of its pore space to evaluate carbonate samples more realistically. In this study, the multiscale micro-CT method and other traditional methods including X-ray diffraction (XRD), casting thin section, scanning electron microscope (SEM), routine petrophysical measurements (RPM), and high-pressure mercury intrusion (HPMI) are first combined to quantitatively describe a distribution of multi-scale pores, throats, and fractures in the target ultra-deep carbonate gas reservoir. The results showed that micro pores (70%–90%), micro throats (>90%), and micro fractures (>90%) dominated in this reservoir. Dolomite accounted for more than 90% of the rock mineral composition in the Qixia reservoir with few clay minerals. Intercrystalline pores and micro fractures were the main pore types and the mean reservoir porosity was less than 2%. Micro fractures play a great role in improving reservoir permeability. The HPMI method presented with errors in the classification of ultra-deep carbonate reservoir types owing to the development of vugs, large pores, and fractures. In this study, a new classification method was proposed to classify this type of reservoirs based on porosity, permeability, and the studied parameters from the multiscale micro-CT method such as throat number and connected porosity proportion. The target reservoir was divided into the following four categories according to the new classification method: fracture macropore type (FMA), macropore type (MA), fracture micropore type (FMI), and micropore type (MI). According to the results of multiscale CT scanning, a strong linear relationship was observed between the number of throats, the connected porosity, and the permeability of the ultra-deep carbonate rock samples studied. Fractures improved the permeability of rock samples by aiding the connection of isolated pores and the expansion of the number of throats. Therefore, the MA and MI types of reservoirs should be properly fractured to increase their productivity.

An Nmr-Based Model for Determining Irreducible Water Saturation in Carbonate Gas Reservoirs

An Nmr-Based Model for Determining Irreducible Water Saturation in Carbonate Gas Reservoirs

Fluid geochemical response recorded in the alteration of marine carbonate reservoirs: the Silurian Shiniulan Formation, southeast Sichuan Basin, China

Natural gas resources in marine carbonate rocks comprise the most significant remaining oil and gas resources in China. Preservation conditions assessment and destruction mechanisms of high-quality carbonate reservoirs play an important role in petroleum resource evaluation in carbonate reservoirs. In the Silurian Shiniulan carbonate gas reservoirs of southeast Sichuan Basin, mineral sequences in fracture-cavity veins, calcite-precipitating fluid sources, and paleo-pressure evolution histories were investigated by Raman quantitative analysis, element characteristics and isotope compositions. The process of reservoir decompression indicated by inclusion analysis and the enrichment of trace elements are all due to the response of reservoir reconstruction. Petrographic observations show two stages of calcite vein occur commonly in fracture-cavity. Stage-1 calcite veins mineralized in a reduction environment as results of hydrothermal activity. Gas accumulation was accompanied by the crystallization and precipitation of the stage-1 calcite veins. Stage-2 calcite vein precipitated during Himalayan tectonics and derived from intensive invaded penetrating fluid, which might be affected by atmospheric freshwater. The density, pressure, and temperature for CH4-bearing fluid inclusions in the stage-1 calcite veins filling was determined by quantitative Raman spectroscopy. Thermodynamic simulations were conducted to constrain pore pressure evolution histories with the establishment of trapping condition of the geo-fluids. Our results suggest that gas generation and charging comprise the main mechanisms for paleo-overpressure development. Identification of fluid sources and understanding pore pressure evolution are keys to study the oil and gas migration and accumulation.

A simulation experiment method for HTHP gas well productivity

In recent years, a series of major natural gas exploration discoveries and breakthroughs have been achieved in deep and ultra-deep carbonate gas reservoirs in the Sichuan Basin, and all discovered gas reservoirs are characterized by great burial depth, complex pore structures and high formation temperature and pore pressure. In order to accurately predict the gas flow rate of single well in high temperature and high pressure (HTHP) gas reservoirs and clarify the gas flow characteristics under formation conditions, this paper establishes a productivity simulation experimental device and method based on the formation temperature and pore pressure of carbonate gas reservoirs in the Middle Permian Qixia Formation of northwestern Sichuan Basin and the Upper Sinian Dengying Formation of central Sichuan Basin. Then, the cores of above mentioned gas reservoirs are selected to carry out the productivity simulation experiment under HTHP. Finally, the gas flow characteristics are studied. And the following research results are obtained. First, the newly established productivity simulation experimental device and method suitable for the conditions of 160 °C formation temperature and 100 MPa pore pressure is used to predict the natural gas AOF (absolute open flow) of Well S-1 in the Qixia Formation gas reservoir of northwestern Sichuan Basin. And the prediction result is better accordant with the calculation result of theoretical model, with a relative error of only 2.12%. Second, based on the Klinkenberg permeability under surface conditions, the single-well gas flow rate calculated from the productivity simulation experiment is better accordant with the gas flow rate from field completion testing; while based on the Klinkenberg permeability under formation conditions, the single-well gas flow rate calculated from the productivity simulation experiment is better accordant with the AOF. Third, the change of formation temperature and pore pressure has a significant influence on rock permeability, and the permeability is more sensitive to stress than to temperature. Fourth, to carry out the reservoir stress sensitivity experiment and the productivity simulation experiment, it is required that core samples be recovered to the formation conditions for aging, or the experimental results may have characteristics of strong stress sensitivity and cannot be used for reservoir engineering evaluation directly. In conclusion, the production rate and AOF of HTHP gas wells can be predicted accurately by means of productivity simulation experiment, based on drilling core samples. In addition, the Klinkenberg permeability under formation conditions can be evaluated by using the relational expression between surface or Klinkenberg permeability under formation conditions and single-well gas flow rate, combined with gas well testing data.

Experimental study on production performance and reserves utilization law in carbonate gas reservoirs

Carbonate gas reservoirs in China are rich in reserves. In the development process, there are many reserves with low permeability, low efficiency and low recovery degree. It is difficult to stabilize gas well production and prolong its life cycle. Under the condition of original water saturation (Sw) of 0%, 20%, 40%, 55% and 65%, respectively, the physical simulation experiment of gas reservoirs depletion development was carried out by using long core multi-point embedded pressure measuring system. The long cores with average gas permeability of 2.300 mD, 0.485 mD and 0.046 mD (assembled from 10 carbonate cores) were used to carry out this experiment. During the experiment, the pressure dynamics at different positions inside the long core and the gas production dynamics at the outlet were recorded in real time to reveal the production performance and reserves utilization law of carbonate gas reservoirs. The results show that the stable production period of tight reservoir in carbonate gas reservoirs is short, and the low production period is relatively long. The stable production time and recovery rate of gas reservoir increase with the increase of reservoir permeability and decrease with the increase of water saturation. The production of tight carbonate gas reservoirs with permeability less than 0.1 mD is greatly affected by pore water, and the reservoir pressure distribution shows a steep pressure drop funnel, and the reserves far from well are rarely used. Therefore, the reserves far from well should be utilized by closing well to restore formation pressure balance, densifying well pattern or transforming reservoir. The variation range of water saturation in the development of carbonate gas reservoirs is influenced by reservoir permeability and water saturation, and closely related to formation pressure gradient in production process. It decreases with the increase of reservoir permeability and increases with the increase of original water saturation. The research results provide a theoretical basis for understanding the relationship between physical properties of carbonate gas reservoirs and production performance, reserves utilization law, and realizing balanced utilization, efficient development and long-term stable production of carbonate gas reservoirs.

Correction to Characteristics of Natural Fractures in an Ultradeep Marine Carbonate Gas Reservoir and Their Impact on the Reservoir: A Case Study of the Maokou Formation of the JLS Structure in Sichuan Basin, China

Correction to Characteristics of Natural Fractures in an Ultradeep Marine Carbonate Gas Reservoir and Their Impact on the Reservoir: A Case Study of the Maokou Formation of the JLS Structure in Sichuan Basin, China

Specified staged acid fracturing of horizontal well for strong-heterogeneity carbonate gas reservoirs: A case study on the gas reservoir of the fourth member of Upper Sinian Dengying Formation in Gaoshiti-Moxi area of the central Sichuan Basin

The carbonate gas reservoir of the fourth Member of Upper Sinian Dengying Formation (hereinafter referred as “Deng 4 Member”) is characterized by deep burial, high temperature, low porosity, low permeability and strong heterogeneity in the Gaoshiti-Moxi area of the central Sichuan Basin. In order to effectively enhance the well productivity and gas reservoir development benefits, this paper defines the reservoir stimulation factor by comprehensively considering the drilling, logging and well type characteristic parameters, to carry out quantitative reservoir evaluation. Then, the refined segmentation method was developed by fully considering the reservoir stimulation factor, in-situ stress and borehole condition. In addition, the differential acid fracturing technology was prepared for different types of reservoirs. On this basis, the specified staged acid fracturing technology of horizontal well for strong-heterogeneity carbonate reservoirs was developed and then applied in the field. And the following research results were obtained. First, the reservoir stimulation factor (y) can be used to accurately evaluate the reservoir characteristics. The high quality reservoir has y ≥ 1.0, the moderate reservoir has 0.5 ≤ y < 1.0, and the low quality reservoir has y ˂ 0.5. Second, the specified staged acid fracturing technology considering the influence of reservoir stimulation factor, in-situ stresses and borehole condition comprehensively is formed. Stimulation measures are applied specifically in different types of reservoir intervals to give full play to the resource potential in each stimulation segment of a long horizontal section, so as to improve the production rate of natural gas reserves in strong-heterogeneity reservoirs. Third, the acid fracturing technology suitable for different types of reservoirs is also different. It is recommended to adopt acid fracturing with gelled acid or diverting acid in high quality reservoirs, acid fracturing with self-generating acid prepad in moderate reservoirs, and acid fracturing with 2–3 stages alternate injection of self-generating acid prepad and gelled acid in low quality reservoirs. Fourth, 69 wells in the production area of the platform margin of Deng 4 Member gas reservoir in Gaoshiti-Moxi area are stimulated with specified staged acid fracturing. The average absolute open flow is 127.6 × 104 m3/d, which is 46.5% higher than that in the early stage of gas reservoir development. In conclusion, the research results provide remarkable stimulation effects, increase the single well gas production greatly and effectively support the efficient development of Deng 4 Member gas reservoir in the Gaoshiti-Moxi area.