Search

Most of the implemented marine gas hydrate test exploitation in the world adopt the depressurization method to break down the hydrate in the reservoir into natural gas and then extract it, but because the gas production results are still a certain distance away from the commercial exploitation, and it mainly stays in the stage of theoretical research and trial exploitation. Based on two trial productions in the Shenhu area of the South China Sea, this study established a model for hydrate exploitation and investigated the impact of different well types on the recovery rates of hydrates and free gas in different development layers during depressurization. For the Class 1 hydrate reservoirs, horizontal wells are the optimal solution to extract hydrate and free gas simultaneously when exploiting the hydrate three-phase layer. Meanwhile, the effect of different well spacing in vertical wells on the recovery rate of hydrate and free gas was studied. It is found that the best recovery efficiency is achieved when the spacing between two wells is 80 m. The lower the bottom flow pressure of the well, the higher the production capacity, but its influence is limited. [ABSTRACT FROM AUTHOR]

Copyright of Natural Gas Industry is the property of Natural Gas Industry Journal Agency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

The efficient development of tight gas reservoirs is significantly enhanced by multi-stage and multi-cluster fracturing techniques in conjunction with horizontal well technology, leading to substantial increases in reservoir drainage volume and individual well productivity. This study presents a tailored fine-fracturing approach for horizontal wells in tight gas reservoirs, supported by a gas–water two-phase numerical simulation model. Utilizing the orthogonal experimental design method, we simulated and optimized various fracture distribution schemes to refine fracturing parameters for maximum efficiency. The optimization was further validated through a comparison with actual well completion and development dynamics. The quantitative results highlight the optimal fracture distribution for horizontal wells, with a horizontal section length of 1400 to 1600 m and 14 to 16 fracturing stages. The pattern features a "dense at both ends and sparse in the middle" strategy, with stage spacing of 80 to 110 m, and a "longer in the middle and shorter at both ends" fracture half-length of 100 to 140 m, achieving a fracture conductivity of 30 μm2·cm. To ensure the economic feasibility of the proposed fracturing strategy, we conducted an economic evaluation using the net present value (NPV) method, which confirmed the robustness of the optimization outcomes in terms of both technical performance and economic viability. The reliability of these optimization outcomes has been confirmed through practical application in the development of horizontal wells in the study area. This research approach and methodology can provide theoretical guidance for the design of hydraulic fracturing operations and the integration of geological and engineering practices in similar unconventional oil and gas reservoirs. [ABSTRACT FROM AUTHOR]

This paper presents an integrated approach to investigate the impact of well spacing on the performance of tight oil and gas reservoirs depleted by advanced multi-stage hydraulic fracture in horizontal wellbores distributed parallelly in rectangular drainage areas. Thus, an analytical models has been developed considering different reservoir configurations and the associated flow rate, cumulative production, ultimate recovery has been recorded. Also, the pressure behavior for early stages of production conditions and the flow regime dominated by boundary effects has been analyzed. The results indicate that well spacing significantly impacts reservoir performance, particularly at late production stages and that well interference and an ee of well spacing optimization in tight oil and gas reservoirs, offering valuable insights for the strategic planning and development of these vital resources. [ABSTRACT FROM AUTHOR]

The risk of well control is high when displacement gas kick occurs in the deep fractured reservoir, and improper handling can easily lead to blowout, which will seriously affect the deep well drilling. Using Fluent software, a simulation model was constructed to depict the interaction of a horizontal well with vertical fractures. The displacement gas kick process was simulated in horizontal well under formation temperature and pressure conditions. An analysis was conducted to assess the impact of fracture width, quantity, as well as the viscosity and density of drilling fluid on the process of gas-liquid displacement. It further compared the effectiveness of three measures in counteracting displacement gas kick: applying back pressure at the wellhead, altering the viscosity and density of the drilling fluid. New findings suggest that the gas-liquid interface within the fracture exhibits a funnel-like shape, where the gas and liquid phases are layered in the annulus and manifest in a streak-like pattern. Fracture width, quantity, and drilling fluid density promote displacement, while drilling fluid viscosity inhibits the displacement. Different from vertical wells, in horizontal wells, displacement gas kick mainly appears in the underbalanced interval. The fracture width primarily determines the size of the displacement window, while the density and viscosity of the drilling fluid exert lesser influence. Horizontal wells are highly sensitive to variations in external conditions when it comes to displacement gas kick. Therefore, enhancing the wellhead back pressure is advisable to address the displacement gas kick in horizontal wells. [ABSTRACT FROM AUTHOR]

The effectiveness of horizontal well drilling in improving the gas recovery efficiency of hydrate production makes it a promising technology for commercial exploitation. However, during horizontal well drilling in hydrate reservoirs, it is crucial to control hydrate dissociation to ensure the reservoir stability and drilling safety. In this work, a two-dimensional model using polar coordinates was built to study the influences of hydrate reservoir characteristics and drilling fluid salinity on gas production. The simulation applies to the hydrate reservoir of the second natural gas hydrate (NGH) production test in the Shenhu area of the South China Sea. The characteristics of hydrate dissociation and secondary formation and the drilling invasion behavior in the NGH layer and the mixing layer (free gas + hydrate) during horizontal well drilling were analyzed and compared. The simulation results indicated that the pressure and temperature transmission rates in the mixing layer (free gas + hydrate) are higher than those in the NGH layer. The invasion amount of drilling fluid in the mixing layer is 18.8 times more than that in the NGH layer. Under the high invasion of the drilling fluid, the hydrate dissociation amount in the mixing layer is similar to that of the NGH layer even though the initial hydrate saturation of the NGH layer was 2.65 times that of the mixing layer. The area of the hydrate dissociation in the mixing layer is much larger than that in the NGH layer, which may lead to the increase in risk of wellbore instability. The secondary hydrate formation is only observed in the NGH layer, which inhibits the drilling fluid invasion. The salinity of the drilling fluid has a more significant impact on the hydrate dissociation near the wellbore in the mixing layer compared to the NGH layer. With the increase in salinity from 3.05 wt% to 20 wt%, the hydrate dissociation range in the mixing layer increases from 0.16 m to 0.23 m, while the hydrate dissociation range in the NGH layer does not significantly change. [ABSTRACT FROM AUTHOR]

Multilayered reservoirs with coexisting free gas and hydrates are primary targets for commercialization, nevertheless, the extremely low permeability greatly limits their extraction efficiency. Herein, multilayer commingled production using horizontal wells stimulated by hydraulic fracturing and thermal fluid injection was proposed to enhance productivity, and the effects of key factors on co-production performance were numerically examined, with the reservoir located in the Shenhu Area as the geological background. The results indicated that due to severe interlayer contradictions, the stimulation capabilities of using fracturing or thermal fluid injection alone were limited, in particular, the extraction of hydrates severely lagged behind. However, their combination exhibited tantalizing productivity due to strengthened inter-well interaction. Reducing the fracture spacing was more effective than increasing fracture conductivity in shortening the production cycle, and intensive fractures with adequate flow capacity were suggested for gas enhancement and water control. When the fracture spacing was reduced from 30 to 5 m and the fracture conductivity increased from 10 to 100 D·cm, the horizontal section length for commercial production (average daily gas production of 50,000 m3 and recovery ratio of 0.7) was reduced from 1758 to 146 m, which is lower than the on-site horizontal section length of 250–300 m. Therefore, the proposed development mode is promising for the commingled production of gas and hydrates. [ABSTRACT FROM AUTHOR]

Natural gas is an eco-friendly energy source with low carbon emissions, making it attractive globally. Understanding gas reservoirs is crucial for sustainable extraction and optimizing potential. However, the complicated fluid flow and production dynamics within intricate gas reservoirs, particularly those characterized by abnormally high pressures and tight porous media, remain partially understood and demand further investigation. In a tight porous medium subjected to high pressure, the assumption of constant permeability is no longer valid. Consequently, a novel composite seepage model has been developed in this study, which considers the responsiveness of permeability to stress. Perturbation theory is employed to address the inherent non-linearity demonstrated by the permeability modulus. The solution of dimensionless pressure responses under constant production conditions is accomplished in the Laplace domain by implementing integral transformation methods. Overall, a comprehensive model is provided to understand the production behaviors of tight gas reservoirs. Moreover, in order to comprehend the transient flow characteristics of tight gas reservoirs, log–log plots are generated through the Stehfest numerical inversion approach, with the flow regimes categorized based on the normalized time phases of the pressure curves. Parametric investigations reveal that stress sensitivity detrimentally affects permeability, resulting in more pronounced pressure declines during the intermediate and late flow phases. The transient seepage model elaborated in this study is able to consider the pertinent formation and well parameters. These interpreted parameters bear significance in designing hydraulic fracturing operations, assessing the potential of tight gas reservoirs, and ultimately enhancing gas production. The presented model not only enhances our understanding of the behavior of horizontal wells in stress-sensitive tight gas reservoirs but also makes a valuable contribution to the broader discussion on transient flow phenomena in petroleum engineering. [ABSTRACT FROM AUTHOR]

Copyright of Natural Gas Industry is the property of Natural Gas Industry Journal Agency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Natural Gas Geoscience is the property of Natural Gas Geoscience and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

The use of Horizontal wells is a common method of underground natural gas storage (UGS), but there is still a need to discuss whether they are more suitable for slotted liner or perforation completions. To address this issue, a numerical model is developed to predict the gas injection rate of horizontal wells while considering the skin factor. Here, a novel uncoupled iteration method is employed to determine the skin factor deriving from turbulence in each time step when the bottom hole pressure is fixed. The uncoupled method begins with an estimate of the initial gas injection rate, which is then used to calculate a turbulent skin factor. This turbulent skin factor is then used to update the gas injection rate, iterating continuously until convergence is achieved. The effects of slotted liner and perforation design parameters, formation damage, and injection pressure on the skin factor are analyzed. The main findings suggest that the error in the gas injection rate calculated by the non-coupled model compared with the coupled model is only 0.6%, yet it can reduce the number of sub-iterations to 1/10 of that required by the coupled model. Moreover, the uncoupled model can provide results within four steps, even when the convergence condition is 10−14. The open area and perforation density play a significant role in determining the connection degree between the horizontal well and the reservoir, with a larger perforation density resulting in a negative skin factor. Perforations are more suitable than slotted liners for reservoirs with severe formation damage, and the difference in skin factor between the two can reach a value of 40.87 when the ratio of the damage zone's permeability to that of the normal reservoir zone is 0.05. It is easier to reduce turbulence damage in slotted liner completions than perforation completions, with the turbulence damage of the slotted liner being only 15.9% of that of the perforation. However, to avoid damage it is crucial to prevent the screen tube from being plugged in, as it might otherwise rise to three to ten times the original level. This study provides a theoretical basis and practical reference for the application of slotted liner and perforation method in UGS horizontal wells. [ABSTRACT FROM AUTHOR]

Horizontal wells offer numerous advantages in the petroleum industry, making them a focal point for research and practice. These wells have a large drainage area, high well output, extensive penetration, high reserve utilization, and the ability to avoid obstacles and challenging environmental conditions. However, in low permeability oil and gas reservoirs, horizontal wells face challenges such as poor connectivity and seepage resistance which hinder production from meeting economic development requirements. To address these challenges, domestic and international fracturing designs for horizontal wells have been developed. Staged fracturing technology for horizontal wells has also been implemented to improve production efficiency. Despite these advancements, there are still main issues present in horizontal well fracturing that need to be addressed This paper aims to provide insights into the various techniques used in fracturing horizontal wells both domestically and internationally. By addressing the challenges encountered in horizontal well fracturing and proposing potential solutions, this paper can serve as a valuable reference for similar reservoir developments. It is crucial for the petroleum industry to continue researching and advancing current technologies to optimize the productivity of horizontal wells in order to effectively meet economic development demands. [ABSTRACT FROM AUTHOR]

Existing fractured gas reservoir development techniques are mainly based on dual medium numerical-simulation models, which can, to a certain extent, effectively simulate natural fractures with high fracture density; however, these models have some limitations, particularly in terms of simulating the fracture morphology and distribution. Considering carbonate gas reservoirs with complex fractures, in this paper, we establish a numerical-simulation model of embedded discrete-fracture seepage in horizontal wells of carbonate gas reservoirs, in order to compare and study the development effect of carbonate gas reservoirs under different horizontal well fracture parameters. The fracture distribution and structure in carbonate gas reservoirs is obtained using an ant-tracking approach based on 3D seismic bodies, and a numerical-simulation model based on the embedded discrete-fractures model is solved using the open-source program MRST. We considered the following parameters: half fracture length, fracture permeability, and horizontal segment length. By changing the fracture parameters of horizontal wells and comparing the gas-production trends, technical optimization in gas reservoir development can be realized. The results show that the embedded discrete-fracture model can effectively solve the difficult problem of characterizing fluid seepage in fractures of different scale in carbonate gas reservoirs. Although gas production increases with increasing fracture length, fracture conductivity, horizontal section length, and natural fracture conductivity, the contributions of these parameters to gas well production capacity are greatly influenced by the natural fractures. [ABSTRACT FROM AUTHOR]

Copyright of Advances in New & Renewable Energy is the property of Editorial Office of Advances in New & Renewable Energy and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Oil Drilling & Production Technology / Shiyou Zuancai Gongyi is the property of Shiyou Zuancai Gongyi Bianjibu and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of China Sciencepaper is the property of China Sciencepaper and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

A new gas hydrate reservoir stimulation method of in‐situ fracturing with transient heating is proposed, in line with analysis of the technological bottlenecks faced by marine gas hydrate production. This method injects the developed chemical reagents into a hydrate reservoir through hydraulic fracturing, releasing heat during the chemical reaction to increase the hydrate decomposition rate. The chemical reaction product furthermore has a honeycomb structure to support fractures and increase reservoir permeability. Based on the geological model of natural gas hydrate in the South China Sea, three development methods are simulated to evaluate hydrate production capacity, consisting of horizontal well, fractured horizontal well and in‐situ fracturing with transient heating well. Compared with the horizontal well, the simulation results show that the cumulative gas production of the fractured horizontal well in one year is 7 times that of the horizontal well, while the cumulative gas production of in‐situ fracturing with transient heating well is 12 times that of the horizontal well, which significantly improves daily efficiency and cumulative gas production. In addition, the variation patterns of hydrate saturation and temperature‐pressure fields with production time for the three exploitation plans are presented, it being found that three sensitive parameters of fracture conductivity, fracture half‐length and fracture number are positively correlated with hydrate production enhancement. Through the simulations, basic data and theoretical support for the optimization of gas hydrate reservoir stimulation scheme has been provided. [ABSTRACT FROM AUTHOR]

Copyright of Journal of Northeast Petroleum University is the property of Journal of Northeast Petroleum University Editorial Office and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Oil Drilling & Production Technology / Shiyou Zuancai Gongyi is the property of Shiyou Zuancai Gongyi Bianjibu and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Natural gas is the most ecological fossil fuel thanks to lower CO2 emissions and no dust pollution, hence it is included into raw materials beneficial from the point of view of environmental protection. Natural gas is extracted from deposits often located at great depths by means of both vertical and horizontal drilling, characterised by high efficiency in terms of obtaining the highest possible productivity, which will allow the existing resources of the deposit to be exploited in the shortest possible time. The paper analyses the influence of factors such as reservoir pressure, the thickness of the reservoir, the length of a horizontal section, average permeability of a reservoir, turbulence coefficient and water exponent on the process of lifting a liquid phase during the operation of a horizontal well located in an underground gas storage facility. The calculations were carried out using data concerning exploitation of the "B" natural gas field and conducted using the "IHS PERFORM" computer programme, which is the leading industry software for carrying out analyses of productivity changes in gas wells. In the final part of the article, conclusions are given, summarising the results of the nodal analysis reservoir performance curve (IPR) and well throughput curve (VLP). [ABSTRACT FROM AUTHOR]

Copyright of Natural Gas Industry is the property of Natural Gas Industry Journal Agency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Natural Gas Geoscience is the property of Natural Gas Geoscience and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Due to the features of low permeability and porosity, the horizontal well and fracturing treatment are effective ways to develop coalbed methane reservoirs, which have the large drain area leading to high producing rate and recovery. The seepage researches in conventional gas reservoir are sufficient, but there are few researches about the flow behavior and pressure distribution in coal bed methane (CBM) reservoirs, especially for multiple-fractured horizontal wells. In this work, based on the seepage theory, point-source function, and Laplace transforms, the mathematic models of gas flow in multiple-fractured wells are derived considering threshold pressure gradient and unsteady flowing. Subsequently, the type curves of multiple-fractured horizontal well in CBM reservoirs are obtained; there are main eight regimes. Finally, the mainly parameters affecting the dimensionless pressure and dimensionless pressure derivative are analyzed. The percolation characteristics of CBM reservoir are more complex than that of conventional gas reservoir for the presence of adsorption/desorption mainly affecting the seepage features in Middle-later Period and boundary behavior. This method does not only enrich our understanding of multiple-fractured horizontal well transport behaviors in coalbed methane reservoirs, but also has an important guiding significance for determining reasonable development program with multiple-fractured wells in the development of coalbed methane reservoir. [ABSTRACT FROM AUTHOR]

Copyright of Oil Drilling & Production Technology / Shiyou Zuancai Gongyi is the property of Shiyou Zuancai Gongyi Bianjibu and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Natural Gas Industry is the property of Natural Gas Industry Journal Agency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Oil Drilling & Production Technology / Shiyou Zuancai Gongyi is the property of Shiyou Zuancai Gongyi Bianjibu and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Petroleum Geology & Recovery Efficiency is the property of Petroleum Geology & Recovery Efficiency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

The old well sidetracking technology is an effective means to stabilize production and increase recovery in later stage of gas field development. Based on economical and reservoir geologic parameters of Sulige low-permeability gas field in China, method and procedure of old well sidetracking selection standards are established, which can effectively improve the sidetracking effect and adequately develop remaining gas. Comprehensively considering corresponding economic parameters including sidetracking drilling cost, operating cost, management cost, gas production rate and gas price, recoverable reserve standard of sidetracking well is determined first. According to gas recovery, gas-bearing area, porosity and gas saturation, standards of remaining geological reserve, reserve abundance and gas pay thickness of sidetracking well are obtained. According to extension direction and distribution characteristics of the sand body in research area, numerical simulation conceptual model of typical sidetracking horizontal well is established, and then standards of old gas well production rate and gas cumulative production rate for sidetracking are obtained. According to the standards, well Su 36-6-9CH is selected to be sidetracked as a horizontal well and its development effect is good. The method has important value of popularization and application in similar low-permeability gas reservoir. [ABSTRACT FROM AUTHOR]

Copyright of Natural Gas Industry is the property of Natural Gas Industry Journal Agency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

In most of gas hydrates reservoirs, the low permeability of sediments limits the commercial production of gas hydrates. Hydraulic fracturing is an efficient way to improve the permeability in hydrate reservoirs. However, how to choose a suitable hydraulic fracturing direction during hydrate production in a 3D hydrate reservoir is still unknown. In this study, the production of gas hydrates and underlying free gas within 10 years by a depressurization horizontal well (along X-axis) under different directions (XY, YZ, XZ plane) of hydraulic fracturing was numerically studied in a 3D model. The simulation results showed that, compared with no hydraulic fracturing, the final increase ratios of the hydrate dissociation volume and gas production volume for the fracturing in XY, YZ, and XZ plane were 188.16 %, 218.96 %, 84.95 %, and 170.29 %, 253.66 %, 102.64 %, respectively, and the final increase ratios of water production amount for the fracturing in XY, YZ, and XZ plane were 140.88 %, 787.25 %, and 381.07 %, respectively. For the hydraulic fracturing in YZ plane, the connection of the production well with the upper and lower strata was earlier, and the underlying free gas was mainly produced in the early period of hydrate production, leading to the higher gas production rate and gas to water ratio in the early period. However, the gas production rate and the gas to water ratio were reduced in the later period of hydrate production due to the consumption of the underlying free gas. For the hydraulic fracturing in XY plane, the connection of the production well with the upper and lower strata was delayed, and the underlying free gas was mainly produced in the later period of hydrate production, leading to the higher gas production rate and gas to water ratio in the later period. By comprehensive consideration, for the depressurization induced hydrate production by a horizontal well along the X-axis, it's suggested that the most suitable fracturing direction should be in YZ plane for a short production period (within 5 years), and it should be in XY plane for a long production period (exceeds 5 years). This study proposes a new point that the suitable hydraulic fracturing direction is related to hydrate production period, which could provide some guidance for gas hydrates production by hydraulic fracturing. [Display omitted] • The HF-YZ improved the gas production rate in the early period of hydrate production. • The HF-XY improved the gas production rate in the later period of hydrate production. • The suitable direction of hydraulic fracturing is related to the production period. • The underlying free gas hindered the dissociation of the hydrate bottom layer. [ABSTRACT FROM AUTHOR]

Copyright of Natural Gas Industry is the property of Natural Gas Industry Journal Agency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Natural Gas Industry is the property of Natural Gas Industry Journal Agency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Combining gas drilling technology with horizontal well drilling leads to improvement in production in oil and gas reservoirs. However, wellbore gas encountering high-pressure formation gas could bring substantial risks in gas drilling process. A theoretical model for pressure wave speed and attenuation coefficient in gaseous phase flow is established and analytically solved by classic fluid-mechanics model and small perturbation theory. The simulation results suggest that the main factors affecting the pressure wave are angular frequency, pipe diameter, and original pressure. In addition, a pressure wave test device is designed to validate the model, and the experimental results fit well with the simulation results. The work presented in this paper can provide a theoretical basis for horizontal section gas drilling and can also detect gas influx to ensure safety and prevent accidents. [ABSTRACT FROM AUTHOR]

Copyright of Oil Drilling & Production Technology / Shiyou Zuancai Gongyi is the property of Shiyou Zuancai Gongyi Bianjibu and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Oil Drilling & Production Technology / Shiyou Zuancai Gongyi is the property of Shiyou Zuancai Gongyi Bianjibu and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

The gas production from marine gas hydrate has always been plagued by low productivity; the complex geological environment poses a significant obstacle to its commercialization. Horizontal wells are thus getting increasing attention due to their advantages in facilitating pressure propagation. Here a pre-embedded dual horizontal well was used to probe its effects in the local temperature distribution and gas production behavior. By doubling the number of boreholes, the flow channels of gas were increased enlarging the decomposition zone. Specifically, this was found to raise the reservoir temperature from −1 °C in a single well to approximately 0 °C. The temperature decline was more moderate due to a weakened Joule-Thomson effect. Consequently, almost 90% of the cumulative gas yield was produced before the lowest temperature occurred, compared to ∼30% in the single vertical well case. This indicates that the gas production from a dual well case was proceeding at a relatively higher temperature, potentially benefitting an enhanced gas production efficiency. An enlarged depressurization region was thus suggested in the field test for a controlled temperature decline to make more use of the sensible heat of the reservoir. • Simulation of horizontal wells by the scheme of pre-embedding. • Increase the minimum temperature during gas production by the dual horizontal wells. • Multiple gas flow paths can alleviate the rapid drop in reservoir temperature. [ABSTRACT FROM AUTHOR]

In this study, a semi-analytical model which couples the reservoir and wellbore, is developed to predict the inflow profile of horizontal wells in a box-shaped gas reservoir with a bottom water zone. The developed gas reservoir flow model is based on a 3D volumetric source model which considers the reservoir properties in the region near the wellbore, in terms of anisotropy, heterogeneity and formation damage. Meanwhile, pressure drops in the wellbore flow model was also considered, due to fluid flow in the horizontal wellbore. The model was calculated by a field case, and the results of the calculation were compared with a commercial simulator: ECLIPSE (Schlumberger, 2011). The comparison between the developed model and ECLIPSE indicates that, a good match was obtained, so that, the model derived in this study can be applied to predict the inflow profile of horizontal well in a gas reservoir with bottom water zone. Moreover, sensitivity analysis is conducted by using various wellbore pressure drops, wall roughness, skin factors, wellbore diameters, anisotropy and producing pressure drops. [ABSTRACT FROM AUTHOR]

Economic success in the Cana Woodford shale play in Western Oklahoma has been largely due to field development using vertically fractured long horizontal laterals. In progressing from the field delineation phase, where sections are held by single well, to the field development phase, where multiple new wells are added to a previously produced section, many of the pre-existing “parent” wells suffer significant reduction in productivity as a result of interference from fracturing operations in the neighboring “infill” wells. We hypothesized that the change in the parent well's productivity was due to changes in fracture conductivity and/or changes in effective fracture length. In order to investigate the validity of our hypothesis, we developed a novel high-resolution spectral gas reservoir simulator to determine whether we could mimic the observed production behavior in the field. In particular, we wanted a simulator that would be immune to spatial truncation errors associated with finite difference schemes, and which would allow us to clearly examine interaction between nanodarcy reservoir matrix and high permeability narrow fractures; in addition, we needed the ability to alter fracture permeability with time to simulate the hypothesized effects of fracture interference. This paper details development of the spectral simulator and demonstrates that changes in fracture conductivity and length due to the interference event can account for observed productivity changes. We qualitatively compare simulator data to observed field data and show that changes in well productivity due to fracture interference can be explained by alteration of fracture half length and/or fracture conductivity. [ABSTRACT FROM AUTHOR]

Interest in tight gas reservoirs (TGR) has quickly spread worldwide. Most researches on the permeability stress-sensitivity of tight gas reservoirs mainly concentrated on experimental approach, physical modeling or pressure behavior analysis, while transient production rate performance does not attract much attention. This study developed a dual-porosity model of a horizontal well in fractured tight gas reservoirs considering the stress-sensitivity effect. The solution methods include variable substitution, perturbation technique, Laplace transformation, Sturm-Liouville eigenvalue theory, orthogonal transformation and numerical inversion. The results showed that the production rate decreases with the increasing of permeability modulus and the derivative curve will be warped up during the whole system late radial flow stage. The influences of other parameters are also analyzed. The work undertaken here has both theoretical and practical significance in predicting production performance and evaluating underground fluid transport in such formations. [ABSTRACT FROM AUTHOR]

A scientific and well-established approach to evaluation and classification of gas wells plays an important role in management of low-permeability gas reservoirs. In this paper, we present a new classification system for horizontal wells, based on dynamic data from 40 wells in the Su-14 block of the Sulige field. We also introduce such evaluation parameters as the drop in well production with a decrease in casing pressure, the casing pressure drop rate, and absolute open flow. We propose using cluster analysis for evaluating the performance of Su-14 wells and for classification of the wells. Analysis of three wells has confirmed that the proposed method is reliable and accurate. This classification method is of considerable theoretical and practical value, and can be used for other similar gas fields. [ABSTRACT FROM AUTHOR]

Increasing temperature can significantly enhance gas desorption and hence improves gas production in shale gas reservoirs, but there are limited practical techniques that can be used to introduce heat into such low permeability reservoirs. This paper investigates the feasibility of an electrical heating method for shale gas desorption enhancement with a mechanistic numerical model. The model incorporated the mechanisms of shale gas adsorption/desorption as a function of low-frequency conduction heating. We evaluate the gas desorption efficiency of heating by two parallel horizontal electrode wells using this model. The electrodes are placed in the two parallel horizontal wells. The impact of the physical properties of formation, electrode length and distance between electrodes, electrical power, and Langmuir volume on gas desorption are investigated. The results indicate that electrical heating using two parallel horizontal electrodes can be an efficient method to enhance shale gas desorption. The temperature and gas desorption increase when the two horizontal electrodes get closer. However, the electrode length and formation resistivity have insignificant impact on gas desorption as long as the injected electrical power is maintained constant. The reservoir thermal properties (heat capacity and conductivity) have a significant impact on gas desorption. Reservoirs with low conductivity and heat capacity get more benefit from the method. The amount of desorbed gas is proportional to the Langmuir volume, so electrical heating method is more applicable to the shale gas reservoir with high Langmuir volume. Gas desorption is directly proportional to the electrical power, therefore, high enough electrical power is required to make the technique successful. [ABSTRACT FROM AUTHOR]

As shown in hydraulic fracture monitoring, the hydraulic fracture path in naturally fractured shale reservoirs is complex, and the method for describing the propagation of fractures in homogeneous sandstone cannot achieve sufficient accuracy when used in shale reservoirs. In this study, a discrete fracture network model is proposed by performing a Monte Carlo simulation on the fracture characteristics of downhole shale cores and shale outcrops in the Longmaxi formation in the Sichuan basin of China. Given the fracture fluid pressure drop and intersections between hydraulic and natural fractures, a 2D numerical model is developed to examine the hydraulic fracture propagation in a randomly fractured shale reservoir using the displacement discontinuity method. Numerical simulations show that (1) the density and length of natural fractures are positively correlated with the complexity of natural fractures when the orientation of such fractures is similarly distributed, (2) the influence of small natural fractures on a hydraulic fracture is localized and cannot change the overall direction of the hydraulic fracture, and (3) hydraulic fractures can cross the natural fracture when the intersection angle and minimum horizontal stress are small enough. The rationality of the numerical model results is supported by the hydraulic fracturing tests on fractured shale outcrops with a true triaxial fracturing system and microseismic monitoring from a hydraulic fracture test well in the Longmaxi shale formation. [ABSTRACT FROM AUTHOR]

Transient rate decline analysis (TRDA) is an important analysis in modern reservoir engineering and applications. Most studies have focused on the threshold pressure gradient (TPG) of low permeability reservoirs and have placed an emphasis on the transient pressure response or steady productivity, whereas transient production decline has not been a focus. This paper presents a transient production decline analysis model of a horizontal well in low permeability gas reservoirs considering the threshold pressure gradient. An accurate solution is determined by employing the Laplace transformation, Sturm-Liouville eigenvalue method, and orthogonal transformation. The bi-logarithmic type curves of dimensionless production and the derivative are plotted by the Stehfest numerical inversion method. Five different flow regimes were recognized, and the effects of the influencing factors, such as the threshold pressure gradient, wellbore storage coefficient, skin factor, horizontal section length, and formation thickness, are discussed. This research contributes to the understanding of transient flow behavior and provides the theoretical basis for efficiently exploiting low permeability reservoirs. [ABSTRACT FROM AUTHOR]

The utilization of a horizontal well has a great significance in the development of sour gas reservoir. The accurate prediction of the productivity of horizontal well will become more and more important in developing sour gas reservoir. In this paper, the effect of sulfur deposition on permeability is considered and a productivity prediction formula of the horizontal well is established. The effects of the length of horizontal well, the effective thickness of the reservoir, elemental sulfur deposition, and reservoir heterogeneity on productivity are analyzed and calculated. The theoretical results show that elemental sulfur disposition and the heterogeneity are the most important factors. According to the field case, the calculating results of improved Joshi’s equation approaches the real productivity, which means that it could be used to predict the productivity of horizontal well at initial stage during sour gas reservoir development. The results can be used as a reference for the development of similar sour gas reservoir. [ABSTRACT FROM PUBLISHER]

Horizontal wells have been widely used to exploit unconventional oil and gas reservoirs across the world. Insufficient hole cleaning has been recognized as one of the main difficulties in drilling horizontal wells. Drilling incidents caused by insufficient hole cleaning increase unproductive drilling time, induce a great amount of additional drilling costs and may even lead to the loss of the well. Drilling a well while maintaining efficient hole cleaning is a systematic process that requires various parameters to implement hole cleaning and requires cooperative effort rather than separate work. Therefore, optimizing multiple parameters to achieve the best hole cleaning effect is of great importance. However, to the author's knowledge, few research studies in this area have been undertaken. The objective of this study is to develop a new method to optimize multiple hole cleaning parameters by introducing the ant colony algorithm. The flow rate, consistency coefficient in power law model and nozzle flow area, which are three easily-adjusted parameters to control the hole cleaning on drilling site, are selected as the optimization variables. The hydraulic constraints that affect hole cleaning optimization are proposed. The mechanism and procedures of ant colony algorithm optimization are described. The practical usefulness of the developed method is demonstrated with a field example. The effect of the selected parameters on hole cleaning is analyzed, and the hole cleaning result after optimization is compared to the data before optimization. The result of the optimization shows that hole cleaning is greatly improved and all constraints are satisfied after optimization. By analyzing the optimization results, it can be concluded that the ant colony algorithm can be used to optimize the hole cleaning problem for horizontal wells. Artificial intelligence can help optimize the drilling of horizontal wells to reduce the risk of unproductive time and decrease drilling costs. The flow rate, consistency coefficient and nozzle flow area should cooperate with one another to minimize the cutting bed height while satisfying all of the constraints. Increasing the flow rate is the most efficient way to reduce the cutting bed height. Decreasing the consistency coefficient and increasing the nozzle flow area can reduce the total pressure loss and enlarge the capacity for increasing the flow rate. Increasing the pressure-bearing capacity of the system is favorable for improving the hole cleaning of horizontal wells. The cutting bed height can be further reduced and the jet velocity can be further increased when increasing the pressure-bearing capacity of the system. [ABSTRACT FROM AUTHOR]

Tight gas reservoir production processes have many challenges, one of which is liquid loading. Installing coiled tubing velocity string (VS) can be an effective tool to extend the production life cycle, and to increase gas recovery. This study focuses on the Daniudi tight gas reservoir in the Northern Ordos Basin, China, as an example of VS application. The basic information and production characteristics of VS wells were firstly analyzed. Then, an evaluation process of VS production effect was established, and the effect after VS installation was divided into three types. The evaluation indexes included water flooded in well, the declining of production rate, the change of cleanup measures and the increasement of the gas–liquid ratio. At last, two methods were used to determine the optimal time to replace the tubing with VS. The first method was a statistical approach, which calculated VS replacement time was no more than 700 days in Daniudi tight gas reservoir, this occurred when the tubing head pressure was more than 6 MPa and the gas–liquid ratio was 0.50–3.00 × 10 4 m 3 /m 3 before VS installation. The second method was a theoretical calculation, in which the critical liquid carrying capacity was higher than the daily gas production, and the corresponding time was the time to incorporate VS. The critical liquid carrying capacity of the calculation model was divided into three parts: the vertical section, the horizontal section and the inclined section. Through calculation analysis, the critical liquid carrying flow rate of the inclined section became the critical flow rate of the well. The actual replacement times of wells were compared with calculated replacement times, to show the validity of the method used in this study. [ABSTRACT FROM AUTHOR]

Drilling horizontal surface-to-inseam (SIS) wells along low permeability coal seams, e.g. <10 mD, is a crucial technology to increase the drainage area for this type of unconventional reservoir. For the first time in the Bowen Basin, a continuous 1900 m long formation resistivity-based high-resolution image log from a SIS well is used to investigate key coal reservoir characteristics including faults, fractures, coal plies, porosity and permeability. This study presents a workflow from image log interpretation to discrete fracture network (DFN) modelling and then to well performance analysis. The interpreted faults from the image logs were used to analyse the uncertainty of fault interpretation from 3D seismic data. The image log was also used in analysing the variation of fracture distribution vertically and horizontally and compared to similar data obtained from vertical wells. All these data were used to understand the variation in productions from three nearby chevron well groups. Results show that the fracture density decreases with increasing Gamma-ray response from the in-seam section, including the intra-seam partings. Regionally, the orientation of fractures and cleats is parallel, sub-parallel or even perpendicular to the regional maximum stress orientation; however, in the study area, the majority of fractures are generally parallel or near parallel to the maximum stress orientation. This study confirmed the trend that the orientation of fractures/cleats rotated from NE to NW from the study area to the north. Because the maximum stress orientation is NNE, this cleat orientation will yield a decrease in coal permeability from south to north. This can explain at least partially the decrease in well performance from south to north. Based on the modelled fractures and their apertures, the upscaled fracture porosity ranged from 0% to 0.01%, with fracture permeability in the x-direction (easting direction) ranging mainly from 1 mD to 10 mD, and with the ratio of permeability in the x-direction to y-direction (northing direction) ranging from 5 to 20. • A continuous 1900 m long image log at a horizontal coal seam gas well was interpreted for fractures and cleats. • The geo-steering data with image logs from the horizontal well accurately locate the faults and their orientations more accurately. • The orientation of fractures/cleats rotated from NE to NW from the study area to the north. • The fractures and their permeability anisotropy on the production from three Chevron wells are analysed. • A discrete fracture network model was built based on drilling and 3D seismic data. [ABSTRACT FROM AUTHOR]

X5 reservoir is a 3000 m deep tight sand-shale interbedded thick reservoir. The horizontal principle stress ratio is around 0.45. The minimum horizontal principle stress is 75–80 MPa, and natural fractures are not abundant. Those conditions limit the generation of fracture network. Treatments based on previous fracturing design have not received good production. Due to extremely thick formation and lack of significant stress barrier, it is hard to maintain the fracture height in expected section. This paper established a 3D fracture propagation model based on finite-element method to simulate multi-cluster staged fracturing, and proposes a cluster space optimization method which considers the fracture geometry of each cluster and the induced stress field between the fractures. This model is used to study three fractures propagating simultaneously from three clusters. Simulation shows that when the cluster space is 10 m, 20 m and 30 m, the middle fracture is severely restricted, and is “enwrapped” by the side fractures. When cluster space is 40 m and 50 m, three fractures propagate in a balanced way. In the cases with “enwrapping” phenomenon, there is “stress slightly diverting area” existing between side fractures, which will reduce the possibility of generating fracture network. Results show that in the 40 m and 50 m cases, minimum stress diverted in the whole regime between the three fractures and no ‘stress slightly diverting area’ exists, which makes fractures more efficient in generating fracture network. But small cluster space will make the stress changes more severe. By comprehensively considering the geometry of three fractures and the induced stress field between fractures, the optimized cluster space is 40 m. Based on this optimization, a 7-stage fracturing treatment of X5-5H well was designed and conducted. The treatment process was smooth and its production was 1.7 times the average production of the adjacent horizontal wells. [ABSTRACT FROM AUTHOR]

Tight reservoir is characterized with low porosity and ultra-low permeability. Horizontal well with multi-stage fracturing is the key technique to maximize stimulated reservoir volume and achieve commercial production. The spacing between perforations has a significant impact on well production. Perforation spacing is currently optimized from the aspects of reservoir simulation. The methods ignore the fact that fracture will generate induced stress field, which may significantly affect the geometry of subsequent fracture. Based on the displacement discontinuity method, this paper established a multi-fracture stress interference model which is able to simulate non-isometric half-length, unequal fracture spacing and arbitrary angle between fracture and wellbore. Data from a tight sandstone reservoir in Sichuan Basin of China are used to analyze the stress field changes and verify the model. The results show that the induced stress creates the maximum compressive stress on both sides of the fracture, and the maximum tensile stress at the fracture tip by stress concentration. The fracture will change the differential horizontal stress ratio in the surrounding area. Position where the differential horizontal stress ratio is lower than 0.3 will be the optimal site to create the complex fractures. Multi-stage fracturing with multiple perforation clusters in one stage is more favorable for complex fracture formation than single perforation cluster in each stage. Data from field verified the proposed perforation optimization method. [ABSTRACT FROM AUTHOR]