Ultimate Gas Recovery Research Articles

Physics-based, data-driven production forecasting in the Utica and Point Pleasant Formation

We introduce a robust, data-driven and physics-based method to forecast the estimated ultimate recovery (EUR) of gas and condensates from the Utica-Point Pleasant Formation. By categorizing 3,410 horizontal wells into eight static cohorts based on the initial gas-oil ratios (GOR) and completion dates, we construct generalized extreme value (GEV) distributions of annual reservoir fluid mass production for each cohort. We use the expected values (means) to build historical, statistical well prototypes for each cohort. These prototypes account for hydraulic fracture deterioration, pressure interference between neighboring fractures, well interference, and advancements in completion technology. We extrapolate mass production of the reservoir fluids for several decades by fitting the scaling parameters of our physics-based model to the statistical well prototypes. A key innovation in this approach is using GEV statistics to generate a time series for each cohort’s GOR and condensate-gas ratio (CGR). We replace the individual production rates from all existing wells with their corresponding extended well prototypes and convert mass to volumetric rates. We sum up the latter rates and provide a base forecast of total reservoir fluid rates and cumulative production, closely matching the historical field production. Our base forecasts predict approximately 23 trillion scf of gas and 200 million barrels of condensate by 2035.The Utica-Point Pleasant Formation is divided into core and noncore areas, each further subdivided into regions based on fluid types. We analyze the future infill potential per square mile in each of these regions, proposing two drilling schedules and four potential future drilling scenarios. We identify approximately 35,847 potential future wells: 12,476 in the core area and 23,371 in the noncore area. The core wells can contribute about 157 trillion scf of natural gas and 0.9 billion barrels of condensate.This study marks the first integrated evaluation of the future production from the Utica-Point Pleasant Formation by combining GEV statistics, physics-based modeling, big-data analysis, geology, proposed drilling programs, and economics. It provides a comprehensive understanding of the Utica-Point Pleasant Formation’s significance in future U.S. shale production.

Analysis of Ultimate Gas Recovery in Shale Reservoirs

Abstract Horizontal wells with multistage fracture treatments enabled economic gas production from shale gas reservoirs. Recovery from a typical shale reservoir is usually quite low as numerous factors can affect the ultimate recovery. However, recovery factors inside and outside the stimulated reservoir volume (SRV), especially the variations spatially and temporally, are not yet fully understood as the numerical simulation of shale gas production is still challenging. In this study, a dual-porosity, dual-permeability model was built to investigate ultimate gas recovery and its spatial variations throughout the production period. Parametric studies were conducted to evaluate the effect of matrix permeability, fracture conductivity, fracture half length, and operating conditions on recovery factors. Systematic and comprehensive numerical experiments were carried out to generate a probability distribution of ultimate recovery factors. The results presented in this article provide insight into the impact that key parameters have on these recovery factors in and outside the SRV and the range of recovery factors one can expect from shale gas reservoirs. Fracture conductivity has the most impact on recovery in the SRV while matrix permeability can affect the recovery outside the SRV significantly. The expected recovery in the SRV is 24% in shale reservoirs. The methodology in this study provides a foundation to develop more reliable models in accurately forecasting ultimate gas recoveries spatially for shale gas reservoirs. The new understanding can be applied to optimize field development, well spacing, and infill drilling to increase economic recovery.

Microscale thermo-hydro-mechanical modeling of thermal recovery of shale gas

The development of horizontal drilling and hydraulic fracturing technologies have made the commercial extraction of shale gas resources come true. However, significant amounts of shale gas are still unattainable even with these technical breakthroughs. One major reason is that up to 85% of total gas-in-place in shale reservoirs could be adsorbed gas. Thus, how much more adsorbed gas can be released will significantly impact the ultimate gas recovery. In recent years, the concept of using thermal stimulation to enhance shale gas recovery has been proposed as more gas desorbs under the higher temperature conditions. In this paper, a fully coupled thermo-hydro-mechanical (THM) model is developed to characterize gas transport and extraction in shale matrix from the microscopic perspective during thermal treatment. A set of partial differential equations are defined to model the coupled processes involved: (1) geomechanical deformation of heterogenous shale matrix; (2) gas adsorption/desorption and flow in heterogenous shale matrix; and (3) thermal transport in heterogenous shale matrix. All these processes are linked together through the porosity and apparent permeability models. This microscale THM model is verified against an analytical solution available in the literature. The verified model is then applied to investigate rock and fluid responses in shale during thermal treatment and the impacts of operation and rock physical parameters on gas recovery. Simulation results indicate that a greater thermal treatment temperature, a lower bottom hole pressure, a larger total organic carbon content and a larger Langmuir volume enhances ultimate gas recovery; and that shale thermal properties and matrix permeability impact initial gas recovery but does not impact ultimate gas recovery.

Differentiation and Prediction of Shale Gas Production in Horizontal Wells: A Case Study of the Weiyuan Shale Gas Field, China

The estimated ultimate recovery (EUR) of shale gas is an important index for evaluating the production capacity of horizontal wells. The Weiyuan shale gas field has wells with considerable EUR differentiation, which hinders the prediction of the production capacity of new wells. Accordingly, 121 wells with highly differentiated production are used for analysis. First, the main control factors of well production are identified via single-factor and multi-factor analyses, with the EUR set as the production capacity index. Subsequently, the key factors are selected to perform the multiple linear regression of EUR, accompanied by the developed method for well production prediction. The thickness and drilled length of Long 111 (Substratum 1 of Long 1 submember, Lower Silurian Longmaxi Formation) are demonstrated to have the uttermost effects on the well production, while several other factors also play important roles, including the fractured horizontal wellbore length, gas saturation, brittle mineral content, fracturing stage quantity, and proppant injection intensity. The multiple linear regression method can help accurately predict EUR, with errors of no more than 10%, in wells that have smooth production curves and are free of artificial interference, such as casing deformation, frac hit, and sudden change in production schemes. The results of this study are expected to provide certain guiding significances for shale gas development.

Lithofacies types, reservoir characteristics and silica origin of marine shales: A case study of the Wufeng formation–Longmaxi Formation in the Luzhou area, southern Sichuan Basin

Shale, which is a fine-grained sedimentary rock, differs in reservoir quality (RQ) and completion quality (CQ) as the result of variations in its mineral and organic-matter compositions. The RQ and CQ directly affect shale gas exploitation. Therefore, classification of the lithofacies types of shale, analysis of the reservoir differences of different lithofacies, and identification of the superior shale lithofacies with the best RQ and CQ are important for decisions on well placement, targeting the “sweet spot” zone and optimizing the expected ultimate recovery of a shale gas well. In this study, several methods including microscopic observation of thin sections, X-ray diffraction analysis, core analysis and elemental geochemistry were used to investigate the lithofacies types, reservoir characteristics and silica origin of the marine shales of the Wufeng Formation–Longmaxi Formation (WF Fm.–LMX Fm.) in the Luzhou area, southern Sichuan Basin, China. The lithofacies characteristics exhibit marked differences through the WF–LMX shale succession. Specifically, the lower gas-bearing zone (LMX-1) is mainly composed of siliceous shales and siliceous–argillaceous mixed shales, whereas the upper gas-bearing zone (LMX-4) mostly contains argillaceous shales and argillaceous–siliceous mixed shales. The lower shale gas reservoirs have a higher silica content and lower clay and carbonate contents than the upper zones, and thus superior petrophysical qualities. The upper part of the WF Fm. (WF-2) and the lower part of the LMX Fm (LMX-1, LMX-2) are rich in bio-chemical authigenic silica, whereas the silica minerals of other intervals are mainly derived from allochthonous terrigenous material. The siliceous shales and siliceous–argillaceous mixed shales with a biogenic quartz content greater than 40% have the best RQ and CQ and are the most promising lithofacies for shale gas in the Luzhou area. Although the upper gas-bearing zones represented by LMX-4 are also good shale gas reservoirs, the RQ, CQ and gas content are generally worse than those of the lower gas-bearing zones because of the silica origin and lithofacies types; thus, extracting shale gas from the upper zones would be a greater challenge.

An improved empirical model for rapid and accurate production prediction of shale gas wells

The estimated ultimate recovery (EUR) of a single shale gas well is one of the important evaluation indicators for the scale and benefit development of shale gas. Nevertheless, due to the lack of engineering and geologic data, as well as the limitations of the existing empirical methods, the current production forecasting methods cannot make reasonable predictions for EUR. Therefore, Duong method is used as the prototype in this paper, a rapid and accurate empirical model for improved production prediction is proposed based on the historical production profile analysis of mass producing wells in Sichuan Basin. The accuracy and universality of the new model are verified by production examples in the Weiyuan, Changning, Luzhou and Yuxi blocks of the Sichuan Basin. The examples illustrate that the new model can be applied well in typical wells, and has no limitation of flow regimes for the production prediction of gas wells. In order to solve the problem of production data fluctuation and decline curve deviation caused by stimulation measures in the production process, a multi-segment production prediction model analysis method is proposed based on the improved model in this study and has been well applied in the field. Most importantly, the new model has clear physical parameters and is easy to operate. Performance of the new model based on production data is as reasonable as the modern production decline methods (including analytical model), which is better than existing empirical methods. • Proposing an improved empirical model, which is rapid and accurate. • Less parameters were selected, the new model still has clear physical meaning. • Application condition of the new model is not limited by the flow regime. • Performance of the new model based on production data is as reasonable as the analytical model. • Multi-segment production prediction model is well applied to gas wells with production data fluctuation.

Development of shale gas production prediction models based on machine learning using early data

The estimate ultimate recovery (EUR) of shale gas in individual well is affected by many factors so that it is difficult to predict accurately. Data-driven methods based on geological and engineering parameters are currently one of the mainstream methods for predicting EUR. However, the importance of early data from gas wells is often overlooked. Therefore, this research set out to use early data, including production and flowback rate data, to develop machine learning models. With the ability to analyze the data by machine learning, the controlling factors on EUR have been analyzed quantitatively. Four schemes have been designed to develop the model, and various machine learning techniques (K-Nearest Neighbor (KNN), Support Vector Machine (SVM), Random Forest (RF), Gradient Boosting Decision Tree (GBDT)) were applied to process the complex patterns in the data. The results show that, except 30-day flowback rate, the most important factor for EUR is the early production data. The relationship between the early flowback rate and EUR is poor. It is not enough to predict EUR accurately provided that only using the flowback rate data. Good prediction results have been obtained by choosing the most important factors. Among the four algorithms, SVM is considered to be the most reliable model because it is suitable for small data sets and performs well in dealing with nonlinear relationships between variables. The mean absolute percentage error is 13.41% in the test set 49 wells, which can be used as the optimal algorithm for EUR prediction only based on early data.

Shale softening degree and rate induced by fracturing fluid under THMC coupling condition

The shale softening behavior caused by hydrofracturing fluid is of great influence for the fracture conductivity and ultimate recovery of oil and gas from reservoir formations. This paper presents an experimental study on the characterization of a shale after being softened by the coupled thermo-hydro-mechanical-chemical (THMC) treatments that simulate the high-temperature and high-pressure rock-fluid interactions occurring in deep reservoirs during and after hydraulic fracturing. Microindentation tests were conducted to characterize the degradation degree and rate of mechanical properties of THMC-treated samples, and X-ray diffraction (XRD), scanning electron microscope (SEM), and micro-computed tomography (micro-CT) were carried out to analyze compositional and microstructural alterations of samples prior to and after THMC treatment. The results show that Young's modulus, hardness, and fracture toughness degrade significantly upon THMC treatment, and the average softening rate was estimated as 0.13 mm/day. The degradation of mechanical properties of the softened zones is primarily owing to the porous microstructure and crack propagation, resulting from the dissolution of carbonates, pyrite oxidation and the clay mineral osmotic swelling. These findings can provide a good insight of shale-fracturing fluid interactions, phenomenological behavior of shale softening that take place in deep reservoirs at elevated temperatures and pressures, and shed lights on the design, and operation of shale gas exploration.

The effect of vacancy defects on the adsorption of methane on calcite 104 surface

Density functional theory calculations are used to study the effect of vacancy defects (ionic Ca and charge neutral CO 3 ) on the adsorption properties of CH 4 molecule on different calcite surfaces. Both types of vacancy defect results in strong adsorption of the gas molecules as compared to defect-free sample. For example, for the 104 surface of the material the methane molecules gets adsorbed stronger by 63.6% and 24.4% for Ca and CO 3 vacancy defects, respectively. Such enhanced adsorption of the CH 4 molecule due to the presence of the vacancy defects is also obtained for the other surface symmetries. Electronic structure calculations show that the latter is due to the orbital-overlap/hybridization between the organic molecules and the substrate. Adsorption capacity of the calcite also increases due to the presence of the defect. Vacancy defects also create energy barriers for the migration of CH 4 on the surface of calcite as revealed in our nudged elastic band calculations. The effect on the CH 4 adsorption and migration becomes more pronounced in the case of Ca vacancy defect. These findings could be of practical importance for, e.g., estimating ultimate gas recovery.

Key geological factors controlling the estimated ultimate recovery of shale oil and gas: A case study of the Eagle Ford shale, Gulf Coast Basin, USA

Based on 991 groups of analysis data of shale samples from the Lower Member of the Cretaceous Eagle Ford Formation of 1317 production wells and 72 systematic coring wells in the U.S. Gulf Basin, the estimated ultimate recovery (EUR) of shale oil and gas of the wells are predicted by using two classical EUR estimation models, and the average values predicted excluding the effect of engineering factors are taken as the final EUR. Key geological factors controlling EUR of shale oil and gas are fully investigated. The reservoir capacity, resources, flow capacity and fracability are the four key geological parameters controlling EUR. The storage capacity of shale oil and gas is directly controlled by total porosity and hydrocarbon-bearing porosity, and indirectly controlled by total organic carbon (TOC) and vitrinite reflectance (R o ). The resources of shale oil and gas are controlled by hydrocarbon-bearing porosity and effective shale thickness etc. The flow capacity of shale oil and gas is controlled by effective permeability, crude oil density, gas-oil ratio, condensate oil-gas ratio, formation pressure gradient, and R o . The fracability of shale is directly controlled by brittleness index, and indirectly controlled by clay content in volume. EUR of shale oil and gas is controlled by six geological parameters: it is positively correlated with effective shale thickness, TOC and fracture porosity, negatively correlated with clay content in volume, and increases firstly and then decreases with the rise of R o and formation pressure gradient. Under the present upper limit of horizontal well fracturing effective thickness of 65 m and the lower limit of EUR of 3×10 4 m 3 , when TOC<2.3%, or R o <0.85%, or clay content in volume larger than 25%, and fractures and micro-fractures aren’t developed, favorable areas of shale oil and gas hardly occur.

The Impact of the Geometry of the Effective Propped Volume on the Economic Performance of Shale Gas Well Production

We analyze the effect that the geometry of the Effective Propped Volume (EPV) has on the economic performance of hydrofractured multistage shale gas wells. We study the sensitivity of gas production to the EPV’s geometry and we compare it with the sensitivity to other parameters whose relevance in the production of shale gas is well known: porosity, kerogen content and permeability induced in the Stimulated Recovery Volume (SRV). To understand these sensitivities, we develop a high-fidelity 3D numerical model of shale gas flow that allows determining both the Estimated Ultimate Recovery (EUR) of gas as well as analyzing the decline curves of gas production (DCA). We find that the geometry of the EPV plays an important role in the economic performance and gas production of shale wells. The relative contribution of EPV geometry is comparable to that of induced permeability of the SRV or formation porosity. Our results may lead to interesting technological developments in the oild and gas industry that improve economic efficiency in shale gas production.

A Production Prediction Method for Shale Gas Wells Based on Multiple Regression

The estimated ultimate recovery (EUR) of a single shale gas well is one of the important evaluation indicators for the scale and benefit development of shale gas, which is affected by many factors such as geological and engineering, so its accurate prediction is difficult. In order to realize the accurate prediction of ultimate recovery, this study considered 172 shale gas wells in the Weiyuan block as samples and selected 19 geological and engineering factors that affect the ultimate recovery of shale gas wells. Furthermore, eight key controlling factors were selected by means of the Pearson correlation coefficient and maximum mutual information coefficient comprehensive evaluation method. The data were divided into training and testing samples. Different numbers of training samples were selected and seven schemes were designed. Based on the key controlling factors, the ultimate recovery prediction model for shale gas wells in this block was established through multiple regression methods. The effectiveness of the prediction model was verified by analyzing the testing samples. The result shows that with the increase of the size of training samples, the error of the ultimate recovery predicted by the model gradually decreases gradually. When predicting the single gas well, the average absolute error of ultimate recovery is less than 20% if the number of the training gas well is more than 80. When analyzing the development potential of similar blocks without drilling, the error of the sum of ultimate recovery is less than 10% if the size of the training gas well reaches 60.

The influence of nitrogen injection duration at the initial gas-water contact on the gas recovery factor

This paper reports a study that employed a digital three-dimensional model of the gas condensate reservoir to investigate the process of nitrogen injection at the boundary of initial gas-water contact at different values of the injection duration. The calculations were performed for 5, 6, 8, 10, 12 and 14 months injection duration. Based on the modeling results, it was found that increasing the duration of the nitrogen injection decreases the operation time of production wells until the breakthrough of non-hydrocarbon gas. Based on the analysis of the technological indicators of reservoir development, it was established that the introduction of technology of the nitrogen injection into a reservoir ensures a reduction in the volume of reservoir water production. The cumulative water production at the time of nitrogen breakthrough to the production wells at the nitrogen injection duration of 5 months is 197,3 thousand m3; of 14 months – 0,038 m3. According to the results from the statistical treatment of estimation data, the optimal value for the nitrogen injection duration was determined, which is 8,04 months. The ultimate gas recovery factor for the optimal period of the non-hydrocarbon gas injection is 58,11 %, and in the development of a productive reservoir for depletion – 34,6 %. Based on the research results, the technological efficiency of nitrogen injection into a productive reservoir has been determined at the boundary of initial gas-water contact in order to slow the movement of reservoir water into gas-saturated horizons. This study results allow the improvement of the existing technologies of hydrocarbon fields development under conditions of water drive. The use of the results of the research carried out in production will make it possible to reduce the volume of cumulative water production and increase the ultimate gas recovery factors to 23,51 %

Study of the efficiency of trapped gas displacement by non-hydrocarbon gases from water-flooded gas condensate reservoirs

Analyzing industrial data and the results of theoretical studies, it was found that the natural gas recovery factor in water-drive gas reservoirs is about 50-60%. Considering the significant volumes of residual gas reserves trapped by formation water, there is a need to improve existing development technologies and search for optimal ways to increase hydrocarbon recovery under conditions of intensive water encroaching. Additional researches using hydrodynamic simulations were conducted in order to study the efficiency of enhanced recovery of residual gas reserves by injecting non-hydrocarbon gases into productive reservoirs. Based on the 3D reservoir model, the study of carbon dioxide and nitrogen injection into the initial gas-water contact was carried out in order to slow down the breakthrough of formation water into productive reservoir. The study was performed for different injection duration of carbon dioxide and nitrogen into productive reservoir. According to the results of the statistical processing of the calculated data, the optimal duration of the nitrogen injection was determined to be 8,04 months. The ultimate gas recovery factor for the optimal period of nitrogen injection is 58,11%. At the time of the carbon dioxide breakthrough into production wells, the optimal duration of the carbon dioxide injection was determined to be 16,32 months. The ultimate gas recovery factor for the optimal period of carbon dioxide injection is 61,98 %. Based on a comparative analysis of the efficiency of using various types of non-hydrocarbon gases as injection agents into productive reservoirs, the high efficiency of using carbon dioxide for injection into the initial gas-water contact was established. Due to the solubility of carbon dioxide in formation water, the ultimate gas recovery factor is significantly higher compared to using nitrogen as an injection agent.

Effects of the rate of carbon dioxide injection at the initial gas-water contact on the recovery factor

The process of carbon dioxide injection into the initial gas-water contact with different rates of its injection, using a 3D model of a gas condensate reservoir, has been investigated. Calculations were carried out for one well injection rate of non-hydrocarbon gas: 40, 50, 60, 70, 80, 90 th.m3/day. According to the calculated results, it has been found that with an increased rate of the carbon dioxide injection into a productive reservoir, the operation duration of production wells decreases until the moment of the carbon dioxide breakthrough. Based on the techno-logical indicators’ analysis of the gas condensate reservoir’s development, it has been found that the introduction of the carbon dioxide injecting technology leads to a reduction in the production of formation water. Due to the injec-tion of non-hydrocarbon gases, a hydrodynamic barrier is created on the initial gas-water contact boundary, which decreases the water influx. Also, the introduction of carbon dioxide injection technology will additionally create an artificial barrier between water and natural gas, which blocks the selective water encroaching and thereby ensure stable waterless operation of production wells. Based on the conducted calculations, the main dependencies have been derived and the corresponding patterns between them have been established. According to the results of the statistical processing of the calculated data, the optimal carbon dioxide injection rate has been determined. At the time of the carbon dioxide breakthrough into the producing well, its optimal well injection rate is 58.17 th.m3/day. The ultimate gas recovery factor for the optimal carbon dioxide injection rate is 63.29 %. Under the same condi-tions during depletion, the ultimate natural gas recovery factor is 53.98%. The results of the carried out studies indicate the technological efficiency of carbon dioxide injection into the initial gas-water contact in order to slow down the formation water encroaching into productive reservoir.

An Integrated Approach to the Development and Reservation of Gas in Central Yakutia

The article provides a detailed overview of diverse problems in gas industry in the Central part of the Republic of Sakha (Yakutia). The problems associated with the provision of recoverable gas reserves, seasonal contrast of produced amounts, production and gas transportation system and the challenges of increasing the gas consumption market are considered in details. A retrospective assessment of the initial geological reserves of natural gas of the Middle-Viluy gas condensate deposit is given. On the basis of production characteristics of deposits and the analysis of development of the worked-out deposits, coefficient of recovery of gas is estimated. It is concluded that under the current system of development of the Middle-Viluy gas condensate deposit, the ratio of the ultimate gas recovery will amount to just 0.5. The inexpediency of construction of boosting compressor station for production of several billion cubic meters of gas is shown. An integrated approach to solving the existing problems of the gas industry is proposed. The necessity of reserving gas raw materials in close proximity to the consumer by creating an subsurface gas storage is noted. It is concluded that only the creation of a gas reservation system will allow to extract most efficiently gas resources of the Central Yakutia and provide the necessary level of energy security.

Numerical investigation of Non-Darcy flow regime transitions in shale gas production

Shale gas reservoirs are organic rich formations with often ultra-low permeability. Gas is stored in free and adsorbed form. Conventional Darcy flow cannot fully describe the gas transport in such porous media. It is thus crucial to study the shale gas production considering different flow regimes and time dependent permeability, which can improve well-induced fracture design and ultimate gas recovery. In particular, this paper will focus on the transition in non-Darcy flow regimes near fracture-matrix interfaces using mathematical modelling. Especially, we investigate conditions at which these effects vanish, and Darcy flow assumptions become reasonable.The model describes a representative well-induced high permeability fracture surrounded by shale matrix. Investigated Non-Darcy mechanisms include apparent permeability, Knudsen diffusion, gas desorption and Forchheimer flow. Pressure depletion is the main driving force for single phase gas flow from the matrix to the fracture and from the fracture to the well. Pressure dependent gas desorption is defined by Langmuir isotherm and is a key production mechanism. This model is implemented in Matlab using Marcellus shale data.Scaling the model shows that recovery of gas depends on two dimensionless number that incorporates geometry relations, time scales of flow, intrinsic parameters of the porous media, non-Darcy constants, adsorption and boundary conditions. The dimensionless numbers define respectively if 1) the fracture or matrix limit the gas production rate 2) if non-Darcy flow is significant in the fracture or matrix. When one of the media limit production, the non-Darcy flow in the other medium has reduced importance and can be excluded from the model. Non-Darcy flow is important if it limits flow in the medium limiting the production. By checking the magnitude of the selected dimensionless numbers, the modelling approach can be determined in advance and significant computational time can be saved.The proposed model provides a tool for interpretation of complex shale gas production systems. It can be used for screening of flow regimes at different operational configurations and hence appropriate modelling approaches. The model can be used to optimise fracture network design and potentially in identifying stimulation operations that may significantly improve production rates and ultimate recovery from unconventional gas reservoirs.

Study on Well Spacing Optimization in a Tight Sandstone Gas Reservoir Based on Dynamic Analysis.

Compared to the shale gas and coalbed methane in China, tight gas has been recently considered as a priority in the exploration and exploitation of unconventional gas resources. In the development of a tight gas field, how to enhance the gas recovery is a prevalent topic. Unlike the conventional gas reservoir, the ultimate gas recovery is not only determined by the geological characteristics but is also affected by other factors such as well drainage area and well spacing design. For tight sandstone reservoirs, the gas recovery can be improved by increasing the drainage area. Moreover, the well drainage area is closely associated with well spacing. Therefore, effective drainage area estimation and well spacing optimization are essential aspects for tight gas exploitation. In this paper, a new optimization workflow is established, which combined dynamic analysis and numerical simulation techniques. First, through interference well test results and production data dynamic analysis, the total gas production can be expressed and predicted. Then the well density can be optimized by the economic evaluation method. Meanwhile, a numerical model is built up to determine the optimal well spacing. This new optimization workflow can provide guidance to the operators of tight gas fields where the interference well test results are available and several years of production data are collected. Furthermore, in the case of the Sulige gas field, the single well drainage area is estimated and the optimal well pattern is obtained by the established approach. The results indicate that the well pattern of 500 m × 600 m is most reasonable for the pilot gas field.

The Ensign Field, Blocks 48/14a, 48/15a and 48/15b, UK North Sea

Abstract The Ensign Field is located in UK offshore licence Blocks 48/14a, 48/15a and 48/15b. The field is located 100 km east of the Humberside coast within the Sole Pit area of the Southern North Sea. The reservoir consists of sandstones of the Permian Rotliegend Group (Leman Sandstone Formation). Reservoir quality has been impacted by diagenesis during deep burial, whereby illitization has reduced permeability to sub-millidarcy scale. The field has been developed with two horizontal production wells, both completed with five hydraulic fracture stages. First gas from the field was achieved in 2012 via the Ensign normally unmanned installation and exported through the Lincolnshire Offshore Gas Gathering System. The field is compartmentalized by multiple regional-scale De Keyser fault zones. A heterogeneous natural fracture network exists with only a limited contribution to flow. Well performance and ultimate gas recovery have been lower than originally anticipated due to sub-optimal completions and a higher degree of compartmentalization than originally expected. The volume of gas that is connected to the wells is limited by low-offset faults, which have been identified by integrating long-term production data, and core, log and reprocessed seismic data. Production ceased in 2018 when the original export route was decommissioned.

Liquid-Loading-Mitigation Strategies Maximize Recovery From Gas Reservoirs

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 194600, “Revisiting Old Sands With a Different Perspective: A Pragmatic Approach for Maximizing Recovery From Gas Reservoirs,” by Sagun Devshali, SPE, Vinod Manchalwar, SPE, Budhin Deuri, Sanjay Kumar Malhotra, Bulusu V.R.V. Prasad, Mahendra Yadav, SPE, Avinav Kumar, and Rishabh Uniyal, ONGC, prepared for the 2019 SPE Oil and Gas India Conference and Exhibition, 9–11 April, Mumbai. The paper has not been peer reviewed. In two gas fields in India, many sands had to be isolated after the wells ceased to flow because of liquid loading in the absence of continuous deliquification. To predict liquid-loading tendencies and to identify opportunities for production enhancement, the performance of 150 gas wells was analyzed. All technically feasible methods of deliquification were evaluated and compared to achieve maximum ultimate gas recovery. Deliquification Techniques ­­in Well-Life Extension A properly designed tubing string can solve the problem of liquid loading to some extent. With a smaller tubing size, gas velocity can be exceeded and can be kept greater than the critical velocity, thus preventing loading in the beginning phase. However, this is not a viable long-term solution. During later stages, the energy of the gas is not sufficient to lift the liquid droplets with even the smallest tubing. At that point, the use of artificial-lift modes becomes necessary. Case Studies Field B. This onshore field in western India produces primarily oil with only 60 gas wells. During the time of study, 17 out of 60 wells in the field were producing gas; the remaining 43 were nonflowing either because of depletion in reservoir pressure or loading. Analysis determined a total of 31 gas wells for deliquification. Of these, in the first phase, two ceased wells (B1 and B2) were selected. Sucker-rod pumps (SRPs) were selected as the most suitable mode of lift in both wells. These wells were then worked over and SRPs were installed in the wells for continuous deliquification. Well B1. This well was completed in the 1507.5- to 1511-m interval, with 2⅞-in. tubing and 5½-in. casing, in 2011. During the time of study in 2017, the well was not producing. The last production re-ported was 3900 m3/d of gas and 1.4 m3/d of liquid. The critical rate to prevent loading in the well has been calculated as 14 000 m3/d. Analysis indicated that the well has been flowing below the critical rate since 2011. A gradient survey performed in October of 2016 indicated that the liquid level was below 370 m. Action Plan and Implementation. The plan included recompleting the well with an SRP unit with the pump placed at 1520 m and tailpipe run to a depth of 1570 m to prevent gas interference. The design included approximately 10 sinker bars to prevent buckling. Well B1 has been completed with the SRP method. A 1½-in. subsurface pump has been placed at 1520 m and tailpipe has been run to a depth of 1570 m. Sucker rods of ⅞ in. have been used as sinker bars. The well has been completed with guides and at the time of writing is producing 6500 m3/d of gas and 6 m3/d of liquid. Well B2. This well was completed with 2⅞-in. tubing in 2002. The well has not produced since August 2015. The last production reported was 8000 m3/d, less than the critical rate of 11 000 m3/d. A gradient survey performed in December 2016 indicated that the liquid level was below 800 m.