Tight Gas Field Research Articles

A Novel Method for Early Warning and Quantitative Evaluation of Liquid Loading in Gas Wellbore Based on Dynamic Production Data: A Case Study of Linxing Tight Gas Field.

Gas wells in Linxing Tight Gas Field are characterized by significant water production, and individual well water production measurement is missing, which pose challenges to predict liquid loading and conduct quantitative evaluations. Moreover, relying solely on flow temperature and pressure testing can be costly and time-consuming. To address these critical issues, we established the prewarning model and quantitative evaluation method for liquid loading. By utilizing those models, real-time judgment and evaluation of liquid loading can be achieved without individual well water production measurements. Our researches reveal that the pressure differential per unit gas production exhibits four patterns for different production stages. In contrast to maintaining a consistent pattern in the absence of liquid loading, the presence of fluid accumulation in production wells can be diagnosed through the increase in the specific production pressure difference within the liquid-loaded production section. Furthermore, the height of liquid loading in the wellbore can be calculated by using the quantitative evaluation model, which can match well with the field tests. The average error can be only 5.9%, and it will offer a novel solution for early warning and quantitative evaluation of wellbore liquid loading in water-producing tight gas fields. In addition, the limitation for strong stress sensitivity effect and high initial water yield-well needs to be broken through in future work.

Parallel role played by tight gas resource in fulfilling United States’ Energy requirement and reducing emission profile from hydrocarbon exploration and production industry (Life cycle analysis lens)

Tight gas has revolutionized the energy picture in North America. The US energy information agency states that the tight gas and oil in the USA has boosted the production of natural gas by around 35% in recent years. This has reduced the need for gas imports. Thousands of meters underground, tight gas trapped in microscopic pores of very dense rocks requires hydraulic fracturing to fracture the rock and releases the gas into the well, known as tight gas. Environmental impact of producing tight gas has caused concerns related to air emissions, water contamination and disposal of waste generated by the tight gas production. There are also concerns related to the possibility of methane escaping into the air during tight gas production and development of this resource class causing minor earth tremors. The advancements in the drilling technologies have recently enabled greater volume of gas to be produce from a single drilling site. This reduces the operational footprint, which is directly proportional to emission profile of tight gas resource. There is a knowledge gap in understanding of Green House Gas (GHG- CO2 equivalent) footprint of tight gas’ resource development because of lack of operational constraints in previous environmental impact assessment of this resource. The objective of this study is to add value and reduce the scientific gap with respect to understanding of tight gas’ resource development techniques, related environmental, and land impact. There remain concerns about development of tight gas related to chemical and methane release into the local water and air, seismic events because of hydraulic fracturing and waste disposal. In order to understand this phenomenon better the work establishes the tight gas production foundation by in depth understanding of 1) Features of Tight gas reservoirs; 2) Geological environment, deposition and generation of tight gas resource; 3) Field development techniques of tight gas resource including construction, production and processing. The work then uses methodology of accounting input and out parameters of cradle to grave tight gas system boundary throughout its life cycle and understands previous GHG (CO2 equivalent) number of tight gas resource development. The work does systematic analysis and summarizes the previously published life cycle analysis to understand further the potential environmental impacts of resource development of tight gas. This will help hydrocarbon exploration and production operators to optimize the operations of tight gas production by better understanding of each sub block of tight gas field development in terms of C02 numbers by using low carbon technologies thus reducing the potential impacts.

Hydraulic fracturing potential of tight gas reservoirs: A case study from a gas field in the Bredasdorp Basin, South Africa

The issue of hydraulic fracturing in the onshore Karoo Basin has triggered an intense political, social and environmental debate in South Africa. This research paper proposes the relatively under-explored F–O tight gas field in South Africa as a demonstration site that can shed light on the ongoing debate on the use of hydraulic fracturing in the Karoo Basin. By combining petrographic and geomechanical analyses with critical velocity experiments and rock mechanics testing, a step-by-step guide for assessing the hydraulic fracturing potential of tight gas reservoirs was presented. K-Means clustering was used to improve the sampling strategy and to capture reservoir heterogeneity. The results obtained showed that K-Means clustering improves reservoir characterisation by revealing heterogeneous intervals, thus optimising petrographic and geomechanical analyses. In addition, the hydraulic fracturing fluid was found not to cause formation damage in the reservoir at a critical velocity of 0.155 ml/min. The elastic properties also showed that the F–O Tight Gas Field has a high degree of brittleness with good hydraulic fracturing potential. Finally, the characterisation of the fractures shows that partially open fractures are prevalent, which can dilate under the high differential stresses in the reservoir. Although further investigation is required, this study has shown that the F–O gas field is a promising candidate for hydraulic fracturing.

Distribution and Main Controlling Factors of Gas and Water in Tight Sandstone Gas Fields: A Case Study of Sudong 41-33 Block in Sulige Gas Field, Ordos Basin, China

Distribution and Main Controlling Factors of Gas and Water in Tight Sandstone Gas Fields: A Case Study of Sudong 41-33 Block in Sulige Gas Field, Ordos Basin, China

Key technologies and orientation of EGR for the Sulige tight sandstone gas field in the Ordos Basin

The Sulige Gas Field in the Ordos Basin is the largest tight gas field in China, with proved reserves exceeding 2 × 1012 m3. As the main contributor to gas production in PetroChina Changqing Oilfield Company, The Sulige Gas Field is in the stage of stable production. Maximizing the stable production period is a focus and challenge for the gas field now. To address a series of problems influencing the efficient development of Sulige gas field, such as large-scale remaining gas reserves between wells/layers and low ratio of employed reserves, the main technologies for enhanced gas recovery (EGR) of tight gas reservoirs were developed by multidisciplinary research with respect to development geology, reservoir engineering, drilling and production process, and surface gathering and transportation. Experiments were conducted on reservoir description and remaining gas characterization, well pattern thickening optimization, vertical well separate-layer fracturing, horizontal-well multi-stage multi-cluster volume fracturing for their improvement and upgrading. The orientation of EGR for tight gas reservoirs is proposed. The following results are obtained. First, well pattern thickening optimization is the most important EGR method, which can increase the recovery rate by more than 6%. Second, based on continuous upgrading and promotion, either of reservoir stimulation technology and drainage gas recovery technology can increase the recovery rate by more than 2%. The gathering and transportation technology which further reduces the wellhead pressure can increase the recovery rate by about 1.5%. Third, the EGR technology should be oriented to maximize the quantity of employed reserves, especially by way of new technologies such as fine remaining gas characterization, well pattern/type optimization, cross-layer fracturing of a multi-thin-layer reservoir by horizontal wells, intelligent drainage gas recovery, and multi-stage pressurization. It is concluded that the development of key EGR technologies will help increase the recovery rate of The Sulige Gas Field by 10%–15%, and will provide an effective support for The Sulige Gas Field to maintain the production at 300 × 108 m3/a for a long term and for the Changqing gas province to increase the production to 500 × 108 m3/a, which will ultimately ensure the national energy security.

A multi-scale geological–engineering sweet spot evaluation method for tight sandstone gas reservoirs

Exploration and development practices have proved that staged volumetric fracturing stimulation in horizontal wells is a key technology for tight sandstone gas development, and reservoir sweet spot is an important basis for the perforation position selection and staged fracturing in the process of well location deployment and reservoir stimulation. Tight sandstone reservoirs are usually characterized by sandstone and mudstone interlayers with different thicknesses, and complex natural fracture distribution and geostress state. It is hard to predict “geological-engineering” dual sweet spots, and these two kinds of sweet spots are usually in different zones. As a result, there lacks a basis for the optimization of fracturing parameters to stimulate tight sandstone reservoirs. This paper establishes a geological sweet spot prediction model which takes into account total hydrocarbon content, reservoir porosity and other factors, then puts forward a 3D multi-scale engineering sweet spot evaluation method which takes into account lithology, fracture morphology, fracture mechanical behavior, and dilatation and shear dilation effect, and finally a “geological-engineering” dual sweet spot evaluation model for tight sandstone reservoirs. Two wells in the tight sandstone gas field in the Linxing Block of the Ordos Basin were selected as a case, and the dual sweet spot profiles, fracturing pressure and SRV were compared and analyzed. The results show that: 1) shear dilation angle influences the distribution of engineering sweet spots at the most in the study area, followed by dissipated energy, elastic modulus and fracture energy; 2) the geological sweet spot zone with a high coefficient is not necessarily the pay zone with high shale gas production; 3) the engineering sweet spot zone with a high coefficient needs lower fracture pressure and can be stimulated relatively sufficiently; 4) high-quality geological sweet spots and high-quality engineering sweet spots are poorly consistent in spatial location. In conclusion, the stimulation of tight sandstone gas reservoirs shall take geological sweet spot as the basis and engineering sweet spot as the guarantee, and the distribution of dual sweep spots should be considered comprehensively. The multi-scale “geological-engineering” dual sweet spot evaluation method proposed in this paper provides important technical support for the prediction of sweet spots of the tight sandstone gas and the optimization of development schemes in the study area.

Driving Forces of Natural Gas Flow and Gas–Water Distribution Patterns in Tight Gas Reservoirs: A Case Study of NX Gas Field in the Offshore Xihu Depression, East China

The driving forces behind gas flow and migration, as well as the associated gas–water distribution patterns in tight gas reservoirs, are not only closely related to the formation mechanisms of “sweet spots”, but also serve as crucial geological foundations for the development of efficient modes and optimal well placement. In this work, three methods, namely, critical gas column height driven by buoyancy, critical pore throat radius driven by buoyancy, and gas–water distribution attitude, were used to quantitatively evaluate the critical conditions for buoyancy and overpressure to get gas flowing in the tight sandstone gas field. In light of the geological background, the driving forces of gas flow/migration and gas–water distribution patterns were comprehensively analyzed. On this basis of the origins of overpressure driving gas flow/migration were identified by using multiple empirical methods, the evolution of overpressure and characteristics of gas–water distribution driven by overpressure were studied by using PetroMod_2014 simulation software. The results show that the four main gas-bearing layers in the NX tight sandstone gas reservoir differ widely in gas flow/migration dynamics and gas–water distribution patterns. Gas accumulation in the H3b layer is influenced by both buoyancy and overpressure. Subsequently, buoyancy leads to the differentiation of gas from water based on density and the formation of edge water. Furthermore, the distribution area of the gas reservoir is determined by the presence of an anticline trap. In contrast, in H3a, H4b and H5a gas layers, buoyancy is not sufficient to overcome the capillary force to make the gas migrate during and after accumulation, and the driving force of gas flow is the overpressure formed by fluid volume expansion during hydrocarbon generation of Pinghu Formation source rocks. Because buoyancy is not the driving force of natural gas flow, H3a, H4b and H5a layers have gas and water in the same layer and produced together, and no boundary and bottom water, where the anticlinal trap does not control the distribution of gas and water, and gas source faults control the boundary of the gas reservoir. These understandings not only significantly expand the gas-bearing target of H3a, H4b and H5a gas layers delineated in the buoyancy driving pattern but also provide an important geological basis for the formulation of an efficient development plan by class and grade for the NX tight sandstone gas field.

Machine Learning Approach Empowers Well Placement in Tight Gas Field

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 22188, “Machine-Learning-Empowered Well Placement in a Large Unconventional Tight Gas Field in China,” by Ting Yu, SLB; Xiangzeng Wang, Shaanxi Yanchang Petroleum; and Alexis Carrillat, SLB, et al. The paper has not been peer reviewed. Copyright 2022 International Petroleum Technology Conference. Reproduced by permission. _ A tight gas field produces gas from a large heterogeneous fluvial reservoir with limited well control in margins and appraisal areas and sparse advanced logs. The principal goal of the study described in the complete paper was to provide a novel solution using machine-learning (ML) techniques to predict sandstone distribution and, to some extent, automate the process of optimizing well placement. The presented work flow overcomes low data quality, scaling, and inconsistency and builds the bridge between geoscience and artificial intelligence (AI) software platforms. Introduction The field is an unconventional gas reservoir covering a vast area in the Ordos Basin in China. This field produces gas from a complex and heterogeneous fluvial reservoir with limited well control for prediction of sand-body distribution. Reservoir distribution and quality prognosis carry large uncertainties. The well spacing between exploration and appraisal wells is approximately 3–4 km; well control is sparser in resource-overlaying areas. As such, reservoir prediction using only well data is marked by uncertainties and can result in high geological risk in placing development wells. In addition to well data, 2D seismic lines cover the full field with a spacing of 2×4 km. The described work flow aims to use all geological and geophysical (G&G) information effectively to optimize well placement and minimize risk of dry wells. It can combine G&G software and AI platforms to deepen data mining and analyze correlations between the seismic waveform and sandstone distribution. This is achieved by using advanced ML algorithms to construct a 3D heterogeneity model with multiple variables. It enables quick organization of data for analysis and interpretation and becomes a tool for supporting real-time drilling. Objective The challenge in this fluvial reservoir is to replicate the sand-body-stacking relationships based on sparse and multiscale data integration. With that objective in mind, ML is an effective tool to automate geoscience work flows. In this study, a new work flow was created that takes advantage of ML in subsurface modeling for efficient and computationally inexpensive forecasting. This method incorporates ML in the context of decision support. The main objectives of the study include the following: - Automatically classify seismic attributes into waveforms and establish their correspondence to log motifs - Improve the effectiveness of 2D seismic data integration with well-log data - Generate a reservoir risk map based on seismic and log-data integration - Construct an advanced 3D geological model with multiple variables - Generate a more-objective interpretation by having less human inference in the data analysis - Bridge the gap between G&G and AI software platforms and lift current G&G software limitations This enabled use of advanced decision-tree-based ML algorithms to generate a geological model.

Regional unconformities and their controls on hydrocarbon accumulation in Sichuan Basin, SW China

Based on outcrop, seismic and drilling data, the main regional unconformities in the Sichuan Basin and their controls on hydrocarbon accumulation were systematically studied. Three findings are obtained. First, six regional stratigraphic unconformities are mainly developed in the Sichuan Basin, from the bottom up, which are between pre-Sinian and Sinian, between Sinian and Cambrian, between pre-Permian and Permian, between middle and upper Permian, between middle and upper Triassic, and between Triassic and Jurassic. Especially, 16 of 21 conventional (and tight) gas fields discovered are believed to have formed in relation to regional unconformities. Second, regional unconformity mainly controls hydrocarbon accumulation from five aspects: (1) The porosity and permeability of reservoirs under the unconformity are improved through weathering crust karstification to form large-scale karst reservoirs; (2) Good source-reservoir-caprock assemblage can form near the unconformity, which provides a basis for forming large gas field; (3) Regional unconformity may lead to stratigraphic pinch-out and rugged ancient landform, giving rise to a large area of stratigraphic and lithologic trap groups; (4) Regional unconformity provides a dominant channel for lateral migration of oil and gas; and (5) Regional unconformity is conducive to large-scale accumulation of oil and gas. Third, the areas related to regional unconformities are the exploration focus of large gas fields in the Sichuan Basin. The pre-Sinian is found with source rocks, reservoir rocks and other favorable conditions for the formation of large gas fields, and presents a large exploration potential. Thus, it is expected to be an important strategic replacement.

Interpretable Predictive Modeling of Tight Gas Well Productivity with SHAP and LIME Techniques

Accurately predicting well productivity is crucial for optimizing gas production and maximizing recovery from tight gas reservoirs. Machine learning (ML) techniques have been applied to build predictive models for the well productivity, but their high complexity and low interpretability can hinder their practical application. This study proposes using interpretable ML solutions, SHapley Additive exPlanations (SHAP) and Local Interpretable Model-agnostic Explanations (LIME), to provide explicit explanations of the ML prediction model. The study uses data from the Eastern Sulige tight gas field in the Ordos Basin, China, containing various geological and engineering factors. The results show that the gradient boosting decision tree model exhibits superior predictive performance compared to other ML models. The global interpretation using SHAP provides insights into the overall impact of these factors, while the local interpretation using SHAP and LIME offers individualized explanations of well productivity predictions. These results can facilitate improvements in well operations and field development planning, providing a better understanding of the underlying physical processes and supporting more informed and effective decision-making. Ultimately, this study demonstrates the potential of interpretable ML solutions to address the challenges of forecasting well productivity in tight gas reservoirs and enable more efficient and sustainable gas production.

Gas and Water Seepage of Tight Gas and Its Application in Well Production Analysis

Changqing tight gas field has been on fashion among China in recent years. Figuring out gas and water seepage behaviors matters a lot for maximizing gas reservoir recovery. One tool for that is to conduct two-phase seepage experiment and reveal seepage features. Experiments show that gas or water’s flowing capacity has a directly positive relationship with its saturation. The larger saturation, the higher permeability. Thus, one method of determining whether a gas well produces water or not is to compare the initial water saturation with its starting-flowing saturation. If the initial gas or water saturation is larger than its critical saturation, it starts to flow. Meanwhile, this critical saturation ranges hugely. For reservoirs with high porosity, permeability, and pore structure like type I, the starting-flowing saturation is 15.6% for gas and 36.6% for water, meaning that it is easily for gas or water to reach the critical saturation and make the seepage happen. The critical saturation in reservoir of type III which has low porosity, permeability, and pore structure is as high as 28.8% for gas and 58.1% for water, indicating that high fluid saturation is needed to have it flow. Finally, four horizontal wells in Sudongnan block are analyzed to verify the method. The prediction that two of them will produce water in the beginning and the other two will not is highly in line with their production data. This method has been proved effective in the prediction of gas wells.

Quantitative Characterization of Shallow Marine Sediments in Tight Gas Fields of Middle Indus Basin: A Rational Approach of Multiple Rock Physics Diagnostic Models

For the successful discovery and development of tight sand gas reserves, it is necessary to locate sand with certain features. These features must largely include a significant accumulation of hydrocarbons, rock physics models, and mechanical properties. However, the effective representation of such reservoir properties using applicable parameters is challenging due to the complicated heterogeneous structural characteristics of hydrocarbon sand. Rock physics modeling of sandstone reservoirs from the Lower Goru Basin gas fields represents the link between reservoir parameters and seismic properties. Rock physics diagnostic models have been utilized to describe the reservoir sands of two wells inside this Middle Indus Basin, including contact cement, constant cement, and friable sand. The results showed that sorting the grain and coating cement on the grain’s surface both affected the cementation process. According to the models, the cementation levels in the reservoir sands of the two wells ranged from 2% to more than 6%. The rock physics models established in the study would improve the understanding of characteristics for the relatively high Vp/Vs unconsolidated reservoir sands under study. Integrating rock physics models would improve the prediction of reservoir properties from the elastic properties estimated from seismic data. The velocity–porosity and elastic moduli-porosity patterns for the reservoir zones of the two wells are distinct. To generate a rock physics template (RPT) for the Lower Goru sand from the Early Cretaceous period, an approach based on fluid replacement modeling has been chosen. The ratio of P-wave velocity to S-wave velocity (Vp/Vs) and the P-impedance template can detect cap shale, brine sand, and gas-saturated sand with varying water saturation and porosity from wells in the Rehmat and Miano gas fields, both of which have the same shallow marine depositional characteristics. Conventional neutron-density cross-plot analysis matches up quite well with this RPT’s expected detection of water and gas sands.

Study on production decline law of fracturing wells in southeast Sulige tight gas field

The main exploitation strategies in southeast Sulige gas field of Ordors Basin are hydraulic fracturing and downhole throttling are mainly adopted. Fractured wells in southeast Sulige gas field have no real stable production process, and the production is constantly decreasing. Fitting effect of adopting one decreasing method to investigate production decline is poor, such as Arps decline, SEPD decline and Duong decline methods. Because of such problems and production characteristics of southeast Sulige, a three-stage decline law study is put forward. The early production decline of gas well belongs to exponential decline, the middle stage belongs to exhaustion decline, and the intermittent exploitation stage belongs to linear decline mode. Most of the production of gas well comes from early and middle production. The study of decline law could provide certain guidance for the evaluation of recoverable reserves and development strategy.

Coupling iron-carbon micro-electrolysis with persulfate advanced oxidation for hydraulic fracturing return fluid treatment

Improving the sustainability of the hydraulic fracturing water cycle of unconventional oil and gas development needs an advanced water treatment that can efferently treat flowback and produced water (FPW). In this study, we developed a robust two-stage process that combines flocculation, and iron-carbon micro-electrolysis plus sodium persulfate (ICEPS) advanced oxidation to treat field-based FPW from the Sulige tight gas field, China. Influencing factors and optimal conditions of the flocculation-ICEPS process were investigated. The flocculation-ICEPS system at optimal conditions sufficiently removed the total organic contents (95.71%), suspended solids (92.4%), and chroma (97.5%), but the reaction stoichiometric efficiency (RSE) value was generally less than 5%. The particles and chroma were effectively removed by flocculation, and the organic contents was mainly removed by the ICEPS system. Fourier-transform infrared spectroscopy (FTIR) analysis was performed to track the changes in FPW chemical compositions through the oxidation of the ICEPS process. Multiple analyses demonstrated that PS was involved in the activation of Fe oxides and hydroxides accreted on the surface of the ICE system for FPW treatment, which led to increasing organics removal rate of the ICEPS system compared to the conventional ICE system. Our study suggests that the flocculation-ICEPS system is a promising FPW treatment process, which provides technical and mechanistic foundations for further field application.

A new method of evaluating well-controlled reserves of tight gas sandstone reservoirs

Based on static geology and dynamic production of typical wells in Yan'an gas field, a convenient method of the wells controlled reserves was established combining with material balance method (MB). The method was applied to 88 wells in Yan'an tight gas field. The results show that: ①Controlled by pore structure, wells are divided into three types based on the morphology of the capillary pressure curve and the analysis of the parameter characteristics, and their productivity is evaluated, respectively. ②The flow material balance method (FMB) ignores the change of natural gas compressibility, viscosity and Z in the calculation. After the theoretical calculation of 30 gas samples, the slope of the curve of the relationship between bottom hole pressure and cumulative production and the slope of the curve of the relationship between average formation pressure and cumulative production are not equal. ③Compared with the results of the MB, the result of the FMB is smaller, and the maximum error is 34.66%. The consequence of the modified FMB is more accurate, and the average error is 2.45%, which has good applicability. The established method is simple, only requiring production data with high precision, providing a new method to evaluate well-controlled reserves of tight gas sandstone. This method with significant application value can also offer reference values for other evaluating methods of well-controlled reserves.

Geochemical Characteristics and Gas Source Contributions of Noble Gases of the Sulige Large Tight Gas Field of Upper Paleozoic in Ordos Basin, China

Tight gas is the fastest developing unconventional natural gas resource, becoming the principal part for gas reserves and production growth in China. The Sulige gas field is the largest gas field and also the typical low porosity and low permeability tight sandstone gas field discovered in China, with an annual natural gas output exceeding 300 billion and cumulative output exceeding 290 billion, playing an important role in ensuring national energy provision, helping China’s energy transformation, and promoting green, low-carbon, environmental protection and high-quality development. Based on sample collection and laboratory analysis, natural gas compositions including hydrocarbons, non-hydrocarbons, light hydrocarbons, and noble gases of the Sulige gas field are systematically analyzed, their genetic identifications are identified, and finally gas source originations and contribution proportions are comprehensively discussed from the perspectives of noble gases and hydrocarbon gases. The main achievements are as follows: 1) natural gases in the Sulige gas field are mainly alkane gases, with high methane content, high drying coefficient, low heavy hydrocarbon contents, low non-hydrocarbon gas contents of CO2 and N2, and relatively low noble gas contents. The helium content is relative 2 order of magnitude higher than the atmospheric value, while neon, argon, krypton, and xenon are relatively about 1–2 orders of magnitudes lower than the atmospheric values. 2) The carbon and hydrogen isotopes of alkanes are generally positive sequence distributions with some part inversion. The 3He/4He values are mainly distributed in magnitude of 10−8, the 40Ar/36Ar is ranged from 506 to 1940, the 129Xe is relative loss, and the 132Xe is relative surplus. 3) Natural gases in the Sulige gas field are typical coal-formed gases generated from a humic organic mother material with maturity from high mature to over mature according to C7 and C8 light hydrocarbons and alkane carbon isotopes. Noble gases are typical crustal genesis, mainly originating from the radioactive decay of crustal source materials. 4) The gas source correlations of noble gases and alkane gases and their quantitative evaluations on source contributions show that natural gases in the Sulige gas field are originated from Carboniferous-Permian coal measure source rocks in Ordos Basin, mainly contributed by coals and supplemented by mudstones, accounting for 55–60% and 40–45%, respectively.

The Mathematical Model of Integrated Coupling of Gas Reservoir-Wellbore-Choke in Sulige Gas Field, China

The tight sandstone gas has huge objective reserves in China and great potential for development. The Sulige gas field is the largest tight sandstone gas field in China. To prevent hydrates and reduce surface pipeline pressure, downhole throttling technology has been widely used in the Sulige gas field, China. Since gas wells in the Sulige gas field are prone to liquid accumulation during production, the installation of downhole chokes makes the liquid accumulation phenomenon of gas wells more complicated, and traditional methods are difficult to simulate and predict production performance. In order to solve this problem, based on the establishment of the gas reservoir seepage model, the wellbore pipe flow model, and the choke nozzle flow model, the gas reservoir-wellbore-choke integrated coupling mathematical model and its solution method were proposed. The case calculation of the choke well in the Sulige gas field is presented. The research results show that the new integrated coupled mathematical model can fully reflect the impact of choke installation and fishing on fluid accumulation and is effectively used for the production performance simulation of choke wells in the Sulige gas field.

Unlocking the Full Potential of NMR Using Machine Learning: A Case Study of a Gas Field With an Oil Problem

This paper describes the application of machine-learning techniques for unlocking the full potential of nuclear magnetic resonance (NMR), using a case study from the Seven Heads gas field. This field has long been recognized but was not developed due to a variety of technical challenges, including the thin-bedded nature of the sediments and the presence of both mobile and immobile viscous residual oil. The oil is a highly viscous liquid which, if produced, could block production tubing due to the shallow depth of the reservoir and associated low pressures. To produce dry gas successfully, identification of both oil and gas zones was necessary to enable gas zones to be perforated and oil zones to be excluded. During the development drilling campaign, the reservoir was appraised using a formation evaluation program specifically designed to address the presence of oil within the thinly bedded reservoir. In conjunction with core data and high-resolution electric logs, NMR logs were used to identify and avoid perforating zones with higher oil saturations. Formation fluid types were derived from the NMR using a pattern recognition technique that analyzes the entire shape of the T1 and T2 distributions to derive the volumes of gas, oil, and water. This machine-learning technique was calibrated using Dean and Stark fluid analysis data and enabled the prediction of continuous water, gas, and oil saturation curves. The results were used to ensure that the perforation strategy avoided oil-bearing sands. This paper describes how the NMR, together with machine learning, has enabled a complex tight gas field to be developed.

Reservoir Characterization of a Tight Gas Field Using New Modified Type Curves for Production Data Analysis—A Case Study from Ordos Basin

Using data from 56 tight gas wells from the study field (Y field) in the Ordos basin of China, this paper presents performance-based reservoir characterization of the study field from production data and geophysical data. Post-fracturing evaluation is realized by applying our new modified production decline type curves for fractured wells. Compared to traditional type curves, our newly proposed modified dimensionless type curves help identify field data diagnostics for various flow regimes of fractured wells and also facilitate the curve matching process with real data to obtain fruitful and crucial reservoir and fractured well information, including key parameters such as reservoir flowing capacity (kh), well productivity, fracture length, drainage area and original gas in place. This paper intends to promote the extensive application of this new technique. With the support of the reservoir information provided by production decline analysis using our modified type curves, the commercial flow units are delineated in terms of interrelated porosity-permeability of sandstone based on pore throat aperture crossplotting and corresponding flow unit productivity. Furthermore, two crossplots of well logging interpreted porosity versus resistivity are constructed, suggesting their good correlated relationships with relative flow unit productivity and initial gas abundance in place, respectively. The two crossplots enable qualitative evaluation of formation penetrated by well, which makes them very useful and practical as wireline logging is basically available for every well. The well production routine is also analyzed systematically by considering a well’s inflow performance, tubing performance and minimal liquid-carrying gas flow rate to investigate if a gas well is producing at optimal conditions or if a measure should be taken to improve the well’s production. Through analysis of the Y field, this study introduces an integrated workflow with the support of the new modified type curves to effectively help understand the reservoir characteristics and the flow behaviors of the tight gas field. The key takeaway from this study is that the new modified dimensionless production decline curves in terms of qDM vs. tDM can be applied in field practice to achieve a systematically comparable understanding of the performance of MHFHWs globally.

Research and test for shut-in after fracturing of volume fracturing technology in Sulige low pressure tight gas

Shut-in after fracturing has become an important supporting technology for volume fracturing in unconventional oil and gas wells, which is helpful for gas and water imbibition replacement to increase single well production. In this paper, the hydraulic pressure, capillary pressure and osmotic pressure, the three main forces that affect well production, are calculated and compared in the Sulige tight sandstone gas field and Fuling shale gas field. The results show that the total forces affecting well production in the Sulige gas field are similar to those in the Fuling shale gas field, and it has the potential to exhibit shut-in after fracturing. For the characteristics of “low pressure” and “water blocking risk” in Sulige gas field, it is suggested that:(1)injecting N2 or CO2 during hydraulic fracturing and reasonably controlling the shut-in time after fracturing, such as shut-in for approximately 30 h, can ensure effective natural fluid flowback while replenishing energy to the formation and reduce the damage caused by water blocking and (2)the waterproof lock slickwater is used in the test wells, and the result shows that slickwater can reduce the reservoir damage and increase well production when compared with guanidine gum fracturing fluid. This research can provide some basis and reference for the field test of shut-in after fracturing in the Sulige tight sandstone gas field.