Horizontal Hydraulic Fracturing Research Articles

Application of Endothermic Fluids to Lower the Breakdown Pressure of Unconventional Reservoirs: Implications for Hydraulic Fracturing.

Unconventional hydrocarbon reservoirs are challenging media to exploit and develop for energy due to very low permeability. As such, unconventional means, such as horizontal drilling and hydraulic fracturing, are typically practiced. During hydraulic fracturing, the formation breakdown pressure is of great importance and determines the fluid pumping cost. Less attention has been given to breakdown pressure reduction for a cost-effective and enhanced hydraulic fracturing operation. The objective of this study is to explore the application of thermochemical fluids to induce thermal shock with the purpose of generating microcracks and reducing the breakdown pressure in high-temperature unconventional reservoirs. For this, thermochemical fluids of an endothermic nature (reduces the temperature when mixed) and Kentucky Sandstone and Eagle Ford Shale were utilized. In particular, we investigated the effect of endothermic reactions between ammonium chloride (NH4Cl) and sodium hydroxide (NaOH) on the strength and breakdown pressure of both samples by applying multiple cycle treatments. The obtained results indicated a significant reduction in both the strength and breakdown pressure of the rocks, with Kentucky Sandstone showing a reduction of 53.07% and Eagle Ford Shale by 34.71% in breakdown pressure. This novel approach not only provides a promising alternative to traditional fracturing methods in high-temperature reservoirs but also could bring a significant reduction in fluid pumping requirements as well as the operational cost of hydraulic fracturing.

Geologic characteristics, exploration and production progress of shale oil and gas in the United States: An overview

We present a systematic summary of the geological characteristics, exploration and development history and current state of shale oil and gas in the United States. The hydrocarbon-rich shales in the major shale basins of the United States are mainly developed in six geological periods: Middle Ordovician, Middle–Late Devonian, Early Carboniferous (Middle–Late Mississippi), Early Permian, Late Jurassic, and Late Cretaceous (Cenomanian–Turonian). Depositional environments for these shales include intra-cratonic basins, foreland basins, and passive continental margins. Paleozoic hydrocarbon-rich shales are mainly developed in six basins, including the Appalachian Basin (Utica and Marcellus shales), Anadarko Basin (Woodford Shale), Williston Basin (Bakken Shale), Arkoma Basin (Fayetteville Shale), Fort Worth Basin (Barnett Shale), and the Wolfcamp and Leonardian Spraberry/Bone Springs shale plays of the Permian Basin. The Mesozoic hydrocarbon-rich shales are mainly developed on the margins of the Gulf of Mexico Basin (Haynesville and Eagle Ford) or in various Rocky Mountain basins (Niobrara Formation, mainly in the Denver and Powder River basins). The detailed analysis of shale plays reveals that the shales are different in facies and mineral components, and “shale reservoirs” are often not shale at all. The United States is abundant in shale oil and gas, with the in-place resources exceeding 0.246×1012 t and 290×1012 m3, respectively. Before the emergence of horizontal well hydraulic fracturing technology to kick off the “shale revolution”, the United States had experienced two decades of exploration and production practices, as well as theory and technology development. In 2007–2023, shale oil and gas production in the United States increased from approximately 11.2×104 tons of oil equivalent per day (toe/d) to over 300.0×104 toe/d. In 2017, the shale oil and gas production exceeded the conventional oil and gas production in the country. In 2023, the contribution from shale plays to the total U.S. oil and gas production remained above 60%. The development of shale oil and gas has largely been driven by improvements in drilling and completion technologies, with much of the recent effort focused on “cube development” or “co-development”. Other efforts to improve productivity and efficiency include refracturing, enhanced oil recovery, and drilling of “U-shaped” wells. Given the significant resources base and continued technological improvements, shale oil and gas production will continue to contribute significant volumes to total U.S. hydrocarbon production.

Investigating the potential of unconventional resources in the Midland Basin: A comprehensive chemostratigraphic analysis of a Cline Shale (Wolfcamp-D) core

Basinal mudrocks assigned to the Wolfcamp Group in the Midland Basin are prolific producers of oil and gas. Technological advancements in horizontal drilling and hydraulic fracturing have been successful in the exploitation of oil and gas from these tight mudrocks. However, many challenges remain unsolved in capturing their macroscale compositional variations to enhance recovery factors and delineate “sweet spots”. To gain improved insights into this fine-grained system, high resolution chemostratigraphic (XRF) data was integrated with mineralogical measurements (XRD), logs, thin sections, and TOC readings, as well as hierarchical cluster analysis to: 1) develop a sequence stratigraphic framework, and 2) reconstruct paleo-redox, as well as ancient water-mass, conditions within the Cline Shale (Wolfcamp-D) from a core in the Midland Basin.This study revealed the presence of three chemo-stratigraphically distinct depositional sequences in the Cline Shale, herein termed Lower, Middle, and Upper Cline from the base upwards. All three units exhibit distinct mineralogical and petrophysical characteristics, were correlated across the basin, and interpreted as third-order sequences. Superimposed onto the three interpreted third-order sequences within the Cline, are potential higher frequency (fourth-order) sequences. These fourth-order sequences typically consist of a lower interval, interpreted as lowstand deposits and an upper interval, which is interpreted as transgressive and highstand deposits. The lower interval is interpreted to be deposited during highly reducing conditions while the upper interval is interpreted to be deposited under suboxic conditions. The highest organic matter preservation is associated with the interpreted lowstand deposits, especially in the Upper Cline. Optimal landing zones (20 ft) are recognized in the upper zone of the Cline Shale based on their high resistivity, total organic richness, elevated siliceous content, and reduced percentage of clay minerals. These zones have been correlated with several nearby wells.The current study demonstrates the wealth of information that can be gained from a single core/well when properly investigated at high resolution with measurements on a cm-scale. The observed shifts in the chemistry of the sediments character and composition are distinct, with implications for sequence stratigraphic analysis, the reconstruction of ancient water-mass conditions, and the identification of “sweet spots” for hydrocarbon resources. The provided analysis lays a foundational basis for further studies in the region, serving as critical data input for expansive regional research efforts.

Dynamic prediction of fracture propagation in horizontal well hydraulic fracturing: A data-driven approach for geo-energy exploitation

Accurate and efficient prediction of hydraulic fracturing fracture propagation is of utmost importance for unconventional reservoir development. Traditional numerical simulation methods require specialized domain knowledge and technical expertise, and machine learning approach can be an alternative predictive tool for fracture propagation. Additionally, existing neural networks cannot be directly applied to hydraulic fracturing scenarios influenced by multiple coupled factors. Thus, this study presents an innovative approach, “AE-ATT-ConvLSTM”, that integrates an additional Convolutional Layer, Autoencoder, and an Attention Mechanism Feature Fusion Layer into the architecture of a Convolutional Long Short-Term Memory (ConvLSTM) sequential image prediction network. This approach aims to predict fracture propagations in different fracturing stages of horizontal wells. The proposed model is trained on a sample dataset consisting of 5000 instances of hydraulic fracturing in horizontal wells. The dataset includes crucial data such as fracture propagation images, wellbore perforation images, natural fracture images, pumping schedules, and reservoir properties. The model achieves remarkable results, with an MSE less than 15 × 10−5, a maximum SSIM of 0.93, and an average FMAE less than 48. The research findings demonstrate that this method significantly enhances prediction efficiency and provides new insights for predicting fracture morphology and optimizing fracturing design.

Micromechanical variation of organic matter (kerogen type I) under controlled thermal maturity progression

Shale formations have recently gained plenty of attention owing to their large amounts of reserves. Horizontal drilling and hydraulic fracturing are the proposed approaches for the development of shale formations. The extended information of the mechanical properties of shale formation is crucial for designing a successful hydraulic fracturing operation. On the other hand, the mechanical properties of such organic-rich formations are greatly affected by the mechanical characteristics of the present kerogen (organic matter), which dramatically changes during the maturation process. In this study, a Qingshankou shale sample containing kerogen type I is mechanically investigated at different maturity levels using the grid nanoindentation approach. To this end, the original immature sample is artificially matured during hydrous (HP) and anhydrous (AHP) pyrolysis. More than 930 nanoindentation tests were performed on grids of 9 × 8 on the surface of 13 samples with different maturities. The test results showed that the presence of water during pyrolysis can significantly affect the shale sample’s mechanical characteristics. In higher temperatures and higher levels of maturity, the role of water becomes more pronounced. During hydrous pyrolysis, kerogen produces larger amounts of oil and bitumen, which become progressively porous. While the original sample showed a Young’s modulus value of more than 48 GPa, and it fluctuated between approximately 19 and 32 GPa during the HP scenario and between 17 and 34 GPa during the AHP process. In terms of hardness, the original sample exhibited an initial value of about 1.1 GPa and more mature samples reflected hardness values in the range of approximately 0.3 and 0.97 GPa in both scenarios. According to the trends of mechanical properties during maturation, mechanical properties decreased at the initial stage of maturation and remained relatively constant during the oil window. Then, another decline was detected at the wet-gas window’s closure. In the dry-gas window, HP and AHP scenarios exhibited different behaviors mainly due to the chemical structure of the kerogen residue.

Femtosecond laser ablation responses of kerogen-rich, argillaceous, and bituminous shale rocks

Shale rocks have become one of the major sources of natural gas and oil. Laser drilling has emerged as a promising technique that can be incorporated into horizontal drilling and hydraulic fracturing processes. In this study, we selected three types of shales (kerogen-rich, argillaceous, and bituminous) with distinct compositions and microstructures and performed femtosecond laser irradiation with different power and energy to investigate their ablation characteristics. Evidence of melting and solidification was observed in all samples, despite the ultra-high pulse frequency of the femtosecond laser. Among the three types of shale rocks, the kerogen-rich shale exhibited the highest ablation rate, while argillaceous and bituminous shale showed lower and comparable rates. The above observations highlight the significance of shale chemistry in influencing laser ablation characteristics under femtosecond laser irradiation. Furthermore, no ablation rate anisotropy was observed when irradiating the samples parallel with and perpendicular to the bedding direction, although shale rocks are microstructurally and mechanically anisotropic.

Study of geomechanical properties of the Pimienta formation with undrained multi-stage triaxial tests, Central-Western Tampico Misantla Basin, Mexico

The Pimienta Formation (J-Pi) of the Tampico Misantla Basin (TMB) in Mexico is known for its potential as unconventional onshore hydrocarbon reserves. The area of interest in this study is located in the western-central part of the TMB, where no significant production has been established from unconventional resources. Given the low permeability and low porosity characteristics of the carbonaceous mudstone in the Pimienta formation, it is necessary to implement techniques to increase the area of flow from the reservoir to the borehole, achieving profitable oil and gas extraction.The geomechanical properties of rock strata are essential inputs for the design and implementation of shale oil and gas production engineering, such as horizontal drilling and hydraulic fracturing. Understanding the capabilities of the rock to yield and contain hydraulic fractures is essential to designing safe and efficient well stimulations. Likewise, the wellbore stability is of critical importance to the successful development of secondary and tertiary recovery systems.In this study, core samples from the Pimienta Formation in the TMB are analyzed through undrained multi-stage triaxial tests, emphasizing the estimated in-situ geo stresses and the effect of the mineral composition of the rock. The geomechanical parameters of compressional strength, Poisson ratio (PR), and Young's modulus of the Pimienta formation are obtained from the analysis of the experimental data and finding correlations to the mineral composition of the samples. A detailed characterization is completed under the conventional rock mechanics methodologies of Mohr-Coulomb and Hoek-Brown failure criterion, as well as Brittleness Index (BI).

Influence of Shale Mineral Composition and Proppant Filling Patterns on Stress Sensitivity in Shale Reservoirs

Shale reservoirs typically exhibit high density, necessitating the use of horizontal wells and hydraulic fracturing techniques for efficient extraction. Proppants are commonly employed in hydraulic fracturing to prevent crack closure. However, limited research has been conducted on the impact of shale mineral composition and proppant filling patterns on shale stress sensitivity. In this study, shale cylindrical core samples from two different lithologies in Jimusaer, Xinjiang in China were selected. The mineral composition and microscopic structures were tested, and a self-designed stress sensitivity testing system was employed to conduct stress sensitivity tests on natural cores and fractured cores with different proppant filling patterns. The experimental results indicate that the stress sensitivity of natural shale porous cores is weaker, with a stress sensitivity coefficient below 0.03, significantly lower than that of fractured cores. The shale mineral composition has a significant impact on stress sensitivity, with the stress sensitivity of clayey argillaceous shale cores, characterized by higher clay mineral content, being higher than that of sandy argillaceous shale, characterized by higher quartz mineral content. This pattern is also applicable to fractured cores filled with proppants, but the difference gradually diminishes with increased proppant concentration. The choice of large particles and high-concentration proppant bedding can enhance crack conductivity. Within the experimental range, the crack conductivity of 20–40 mesh quartz sand is more than three times that of 70–120 mesh quartz sand. At an effective stress of 60 MPa, the conductivity of cores with a proppant concentration of 2 kg/m2 is 3.61 times that of cores with a proppant concentration of 0.3 kg/m2. Under different particle size combinations of proppant filling patterns, the crack conductivity at the crack front with large-particle proppants is 6.21 times that of mixed bedding. This study provides valuable insights for the hydraulic fracturing design of shale reservoirs and optimization of production system parameters in subsequent stages.

A three-dimensional numerical well-test model for pressure transient analysis in fractured horizontal wells with secondary fractures

During oil and gas reservoir development, multi-stage horizontal wells (MFHWs) and hydraulic fracturing techniques can effectively increase estimated ultimate recovery. However, there still lacks an understanding of the three-dimensional (3D) pressure transient behaviors of multi-stage fractured horizontal wells with secondary fractures. To narrow this gap, a three-dimensional numerical well-test model based on a discrete fracture model and unstructured tetrahedral grids is developed to study the pressure transient behaviors of MFHWs with secondary fractures. The pressure transient solutions of MFHWs with secondary fractures have been demonstrated by model verifications. The results show that the proposed model can accurately capture the complex transient flow around fractures, including early radial flow that is not easily captured by two-dimensional numerical well test models. The proposed model classifies the flow regimes of a MFHW as: wellbore storage and skin effects, early radial flow, bilinear flow, linear flow, elliptical flow, pseudo radial flow, and pseudo-boundary dominated flow. It is found that the fracture geometry has a relatively large effect on the shape of the pressure derivative curve in this work. The hydraulic fracture half-length has the greatest impact on the pressure transient behaviors of the MFHW, followed by fracture height and secondary fracture half-length, as found in this study. Additionally, fracture parameters are evaluated, and actual well testing data are interpreted, taking into account the fracture height. This work is meaningful to understand the three-dimensional pressure transient behaviors of MFHWs with secondary fractures.

CLIMATE CHANGE MITIGATION STRATEGIES IN THE OIL & GAS SECTOR: A REVIEW OF PRACTICES AND IMPACT

Climate change mitigation has become a pressing global challenge, with the oil and gas sector being a significant contributor to greenhouse gas emissions. This review examines climate change mitigation strategies within the oil and gas industry, focusing on practices and their impact. The oil and gas industry faces increasing pressure to reduce its carbon footprint and transition towards cleaner energy sources. Various mitigation strategies have been implemented, including technological innovations, operational improvements, and investments in renewable energy. These strategies aim to minimize greenhouse gas emissions, improve energy efficiency, and transition towards low-carbon alternatives. Technological innovations play a crucial role in mitigating climate change within the oil and gas sector. Advanced drilling techniques, such as horizontal drilling and hydraulic fracturing, have enabled companies to extract oil and gas more efficiently, reducing emissions per unit of production. Additionally, carbon capture, utilization, and storage (CCUS) technologies have been developed to capture and store carbon dioxide emissions from oil and gas operations, preventing them from entering the atmosphere. Operational improvements, such as reducing methane leaks and flaring, are also essential for climate change mitigation in the oil and gas industry. Methane is a potent greenhouse gas, and minimizing its release during extraction, processing, and transportation is critical for reducing the sector's overall emissions. Companies have implemented measures such as leak detection and repair programs, improved equipment maintenance, and enhanced monitoring systems to mitigate methane emissions effectively. Furthermore, investments in renewable energy and low-carbon technologies are increasingly common among oil and gas companies. Many companies are diversifying their portfolios to include solar, wind, and bioenergy projects, aiming to reduce their reliance on fossil fuels and contribute to the transition to a low-carbon economy. In conclusion, climate change mitigation strategies in the oil and gas sector encompass a range of technological, operational, and investment initiatives aimed at reducing greenhouse gas emissions and transitioning towards cleaner energy sources. While progress has been made, ongoing efforts and collaboration between industry stakeholders, governments, and civil society are essential to achieve meaningful impact in mitigating climate change.
 Keywords: Climate Change, Mitigation, Strategies, Oil and Gas Sector, Practices and Impact.

Research on Hydraulic Fracturing Technology of Long Boreholes along Strata of High Vast Thick Coal Seam

Gas extraction is a major technique for regional gas regulation and coal and gas comining in China. Assuring effective gas extraction operations is a crucial step in ensuring the supply of energy. The effect range of extraction drilling, pressure relief degree, and standard period of gas extraction are all constrained because of the geological constraints affecting coal gas permeability and occurrence. Combined with the advantages of directional drilling and high-efficiency pumping technology and antireflection enhanced pumping technology of hydraulic fracturing, directional long-drilling hydraulic fracturing can effectively improve the efficiency of gas control and expand the scale of gas control. The present study focuses on the exploration of directional long-hole hydraulic fracturing technique in thick coal seams with high gas content using Dafosi Mine as a case study. The research findings demonstrate that hydraulic fracturing contributes to the enlargement of pore size, pore density, and pore connectivity in coal seams. In-depth research was conducted on the expansion of coal seam fractures during the hydraulic fracturing process using the RFPA3D-flow numerical simulation program. Additionally, a comprehensive analysis of stress distribution around the fractures under the flow-solid coupling condition was performed. To further improve the effectiveness of hydraulic fracturing technique, the research team optimized the fracturing tools and construction processes in the four coal seams of Dafosi Mine. The impact of segmented hydraulic fracturing in coal seam bare hole drilling was also studied. Furthermore, an investigation method specific to the coal seam bare hole segmented hydraulic fracturing effects applicable to Dafosi Mine was developed. The maximum fracture extension pressure, minimum fracture closure pressure, and fracture morphology change characteristics during drilling and fracturing were measured, and the fracturing influence radius of coal seam was determined to be 46−58 m, the gas extraction concentration after fracturing increased by 2.20–4.22 times, and the 100-m extraction flow increased by 4.93–11.03 times. It gives other mines technical assistance so they can keep advocating and utilizing the horizontal directional long-drilling stage hydraulic fracturing technique.

The present-day in-situ stress field and its effect on shale gas development in Zigong area of southern Sichuan Basin

The Zigong area in southern Sichuan Basin is one of the key shale gas production areas in China, and the Longmaxi and Wufeng Formations within it are currently the key exploration and development layers. The present-day in-situ stress field has a significant impact on well trajectory deployment, horizontal well construction, hydraulic fracturing and other aspects. However, it has not been finely quantified in shale gas reservoirs of Zigong area, making it difficult to effectively guide development practice. Therefore, this study constructed a geomechanical model of the target layer in the Zigong area, quantitatively characterized the distribution of present-day in-situ stress, and explored its shale gas development effects. The results show that: (1) Based on the analysis of drilling induced fractures obtained from rock acoustic emission experiments and imaging logging interpretation, the dominant orientation of the maximum horizontal principal stress in the target layer is mainly NW-SE-trending; (2) The horizontal principal stress difference in the Layer S1l1-1−1 and Wufeng Formation is 5–30 MPa (the majority is 6–15 MPa) and 5–35 MPa (the majority is 6–18 MPa), respectively. Low stress difference values are mainly concentrated in the southeastern and northern parts. The overall prediction accuracy is high, with an error rate of less than 8% for the Layer S1l1-1−1 and less than 10% for the Wufeng Formation; (3) Based on rock acoustic emission experiments and finite element model simulation results, the study area is mainly under strike-slip stress faulting mechanism; (4) Due to the influence of the strike-slip faulting stress mechanism, when deploying horizontal wells in the area, priority should be given to selecting areas with low stress mechanism factor (Aφ) and low stress differences, to achieve better fracturing and transformation effects and reduce the risk of casing deformation and wellbore instability.

Promoting the uniform propagation of multi-fracture through adjusting the injection rate and perforation parameter: A numerical study

The strong stress interference and fluid competitive distribution result in the non-uniform propagation of multiple fractures during horizontal well multi-stage hydraulic fracturing (HWMHF). The uniform stimulation effect can be effectively improved by adjusting the injection rate and perforation scheme. In this work, a two-dimensional fluid–solid fully coupled multi-fracture propagation model is established to investigate the pattern of multi-fracture propagation and the flow distribution. The considering factors include the fluid injection rate, the perforation parameters, and the reservoir heterogeneity. The pipe element is developed to realize the free fluid distribution among multiple fractures. The results show that multiple fractures are more likely to initiate simultaneously and propagate uniformly with a higher fluid injection rate. The stress interference among multiple fractures can be balanced and the equilibrium propagation degree of multiple fractures can be greatly improved by reducing the perforation number. In the homogeneous reservoir, when the fluid injection rate is 12 m3/min and the perforation number per cluster is reduced to 10, the difference coefficient of fluid distribution can be reduced to 3.31%. In the heterogeneous reservoir, multiple perforation clusters with different tensile strengths can generate nearly uniform fractures by increasing the fluid injection rate and reducing the perforation number. When the fluid injection rate is 12 m3/min and the perforation number per cluster is 6, the difference coefficient of fluid distribution can be reduced to 3.26%. This work is of great significance in clarifying the propagation pattern and optimizing the fluid injection rate and the perforation number to improve the uniform propagation degree of multiple fractures.

Guest Editorial: The Engineer of the Future

Recently, at the SPE Annual Technical Conference and Exhibition, I was asked a question about the ‘engineer of the future.’ As we take a pause to turn the page to next year, I believe now is a prescient time to contemplate what’s next for petroleum engineering. Throughout my career, I’ve been able to witness great change in our industry as the shale revolution took hold making horizontal drilling and hydraulic fracturing commonplace, diagnostic and modeling tools improved in access and cost, and data became more timely and readily available. This led to a tremendous period of US energy supply growth and decades-long productivity improvements. Looking forward, I believe there are three trends that engineers should consider: 1) applying “new” tools to solve “old” problems, 2) connecting the dots via hybrid engineering, and 3) organizing, directing, and inserting data predictions into their workflow. These are not only my views but also the views of Devon’s talented engineers. Old problems will meet new solutions. The past decade has been dominated by unconventional horizontal development that was first pioneered in the Barnett Shale for natural gas and shortly thereafter transitioned into oil-focused development in the Bakken and Eagle Ford. Today, the Permian Basin continues to grow in total supply as the stacked pay is developed. Engineers should take stock of the tool set we have acquired during this era with a mindset to deploy these methodologies to tier II unconventional extensions, previously developed or bypassed conventional formations, offshore and international opportunities, enhanced recovery projects such as EOR and refracturing, and new energy opportunities like geothermal. To make these future opportunities competitive and meet the global demand for energy, we will likely need a combination of price, technology, and cost improvements. Engineers are critical to the latter two. To better illustrate these points let’s utilize examples. Drilling rig specification improvements have been coupled with material science and design improvements in bottomhole assemblies. The outcome is improved topdrives and mud pressure systems to power more durable and efficient downhole motors and bits, thus reducing failures, enhancing the efficiency of a rig’s daily footage, and enabling longer laterals. If we pivot to the completion space, our diagnostics for frac geometry have gone from limited and costly to a menu of options that provide fit-for-purpose diagnostics and costs. Devon deployed its first permanent fiber diagnostics in unconventional shale in 2012. Today, the same system is readily available but for a much lower cost. However, more frequently Devon has supplemented this tool with dip-in fiber and a proprietary methodology called sealed wellbore pressure monitoring to gather more frequent data points for frac geometry and design. As our team conducted, in cooperation with the US Department of Energy (DOE), a novel Eagle Ford project capturing horizontal core and completion diagnostics, we recognized that our designs have tremendously improved in efficiency but still have potential to capture more of the resource via initial and secondary fracturing efforts.

Uncertainty and investment: Evidence from domestic oil rigs

AbstractWe provide new evidence on the response of investment to uncertainty, using granular and high‐frequency (weekly) data on domestic oil drilling and oil prices since 2012, corresponding to the period of widespread horizontal drilling and hydraulic fracturing in the United States. Weekly data permits much weaker identifying restrictions than is required with monthly data that is common in the literature. We measure domestic drilling activity by the number of rigs drilling for oil, and we measure oil uncertainty by implied volatility from options on oil futures and the return on delta‐neutral straddles from options on oil futures. We show that the number of oil drilling rigs are tightly linked to both oil prices and oil uncertainty, and we find that oil uncertainty significantly decreases the number of drilling rigs, with a one standard deviation increase in uncertainty reducing the number of drilling rigs by up to 5%.

Deep neural network model for estimating montney shale gas production using reservoir, geomechanics, and hydraulic fracture treatment parameters

The development of a shale gas project requires an accurate prediction of the production potential owing to the high cost of horizontal well drilling and hydraulic fracturing treatment. Previous research developed models for estimating shale gas production based on the reservoir and hydraulic fracturing data. They reported a high degree of uncertainty in the prediction as a result of the fracture properties' locking information. This research aims to reduce the uncertainty in shale gas production prediction by developing a deep neural network (DNN) model that incorporates reservoir, geomechanics, and fracture treatment parameters to predict monthly Montney shale gas production. The DNN model, optimized using the Keras Tuner optimization tool, employs a unique architecture of eight hidden layers and integrates production time as an input feature. This allows the model to predict production rates at any time point in the reservoir's life cycle. The prediction model was developed using 102,000 simulation data and blind tested using other 18,000 unseen simulation data, which were achieved by coupling a hydraulic fracture simulator with a reservoir simulator. The model revealed an average error of 13.41%, with a promising correlation between predicted and simulated gas production rates (R2 > 0.85), and cumulative gas production (R2 > 0.89). These results demonstrate the model's accuracy in predicting Montney shale gas production and its utility in assessing the economic viability of shale gas projects. In conclusion, the research introduces an important advancement in reducing uncertainty in shale gas production prediction, providing an accurate tool that has wide applications in assessing the viability of shale gas projects and suggesting further exploration in refining the prediction techniques for other geological formations.

Production prediction based on ASGA-XGBoost in shale gas reservoir

The advancement of horizontal drilling and hydraulic fracturing technologies has led to an increased significance of shale gas as a vital energy source. In the realm of oilfield development decisions, production forecast analysis stands as an essential aspect. Despite numerical simulation being a prevalent method for production prediction, its time-consuming nature is ill-suited for expeditious decision-making in oilfield development. Consequently, we present a data-driven model, ASGA-XGBoost, designed for rapid and precise forecasting of shale gas production from horizontally fractured wells. The central premise of ASGA-XGBoost entails the implementation of ASGA to optimize the hyperparameters of the XGBoost model, thereby enhancing its prediction performance. To assess the feasibility of the ASGA-XGBoost model, we employed a dataset comprising 250 samples, acquired by simulating shale gas multistage fractured horizontal well development through the use of CMG commercial numerical simulation software. Furthermore, XGBoost, GA-XGBoost, and ASGA-XGBoost models were trained using the data from the training set and employed to predict the 30-day cumulative gas production utilizing the data from the testing set. The outcomes demonstrate that the ASGA-XGBoost model yields the lowest mean absolute error and offers optimal performance in predicting the 30-day cumulative gas production. Additionally, the mean absolute error of the unoptimized XGBoost model is markedly greater than that of the optimized XGBoost model, indicating that the latter, refined through the application of intelligent optimization algorithms, exhibits superior performance. The insights gleaned from this investigation have the potential to inform the development of strategic plans for shale gas oilfields, ultimately promoting the cost-effective exploitation of this energy resource.

Tight and Shale Oil Exploration: A Review of the Global Experience and a Case of West Siberia

Shale and tight oil reservoirs, with horizontal wells and hydraulic fractures, typically have a recovery ratio of around 10%. The exploration of tight oil and shale in North America has proven economically viable, thanks to advancements, such as horizontal wells, hydraulic fracturing, and other enhanced oil recovery techniques. Taking inspiration from the global experience (the North American shale experience), the exploration and development of the West Siberian tight and shale reserves was more focused on the reported best practices of the exploration of North American shale. In this study, the advance in the specific areas of shale and tight oil exploration was considered, with more emphasis placed on the progress in the exploration of West Siberian shales. According to the review literature, thermal enhanced recovery methods capable of converting organic matter into hydrocarbons were studied more than other methods of enhanced oil recovery. Aligned with global trends, there has been a growing focus on research aiming to integrate data-driven approaches and pore-scale simulations to enhance recovery from tight and shale formations. Multiple pilot studies have showcased promising prospects for implementing multistage hydraulic fracturing. Nevertheless, there are limited pilot studies dedicated to enhanced oil recovery methods for West Siberian shale.

Utilizing Reservoir Model to Optimize Future Oil Production for Hydraulic Fracture Wells in Tight Reservoir

The tight oil reservoir has low porosity and permeability generally suffers from rapid declines in production rates for oil wells, especially in southeast Iraq in the Halfaya oil field of the Sadi Formation, which is considered as tight oil reservoir with a reserve of about 25%; their OOIP accounts for more than a quarter of the total in the H oilfield. Implementing a pilot hydraulic fracture technique was a focus of attention in Iraq to increase the production rates, but the main issue faced in hydraulic fracturing wells was producing with a high oil rate for a short period of time then starting to decline rapidly, so a reservoir dynamic model was utilized to achieve the purpose of this study. The purpose of this study is to predict the production rate to prolong the production stabilization in horizontal and vertical hydraulic fracturing wells in order to avoid highly depleted fracture storage capacity and production below the bubble point. Recognize a practical procedure with horizontal hydraulic fracturing wells to reach stabilization. The reservoir simulator results show that a good history matches till 2021, predicting the rates that stabilize the production with flowing pressure above the bubble point pressure till 2025, producing rates for an eight-stage well with 700 BOPD and 900 BOPD for an eleven-stage well, whereas the rate for a vertical hydraulic fracture well is 225 BOPD. A practical procedure in horizontal hydraulic fracturing wells is achieved by keeping the wellhead pressure constant during the production period to stabilize transient behavior.

Comparative Study between Different Oil Production Enhancement Scenarios in an Iraqi Tight Oil Reservoir

This paper presents a comparative study between different oil production enhancement scenarios in the Saadi tight oil reservoir located in the Halfaya Iraqi oil field. The reservoir exhibits poor petrophysical characteristics, including medium pore size, low permeability (reaching zero in some areas), and high porosity of up to 25%. Previous stimulation techniques such as acid fracturing and matrix acidizing have yielded low oil production in this reservoir. Therefore, the feasibility of hydraulic fracturing stimulation and/or horizontal well drilling scenarios was assessed to increase the production rate. While horizontal drilling and hydraulic fracturing can improve well performance, they come with high costs, often accounting for up to 100% of the total well cost. To ensure economically viable flow rates and achieve maximum ultimate oil recovery, a technical and economic comparative study was conducted. The results indicate that hydraulic fracturing offers promising outcomes, with a total oil production of 153,816 Mbbl over 30 years from 25 fractured wells, resulting in a final Net Present Value (NPV) of 3,583.32 MM$. In contrast, the planned two horizontal wells exhibit lower eventual production and NPV compared to the majority of fractured wells. However, the 2000 m lateral section of well HF00Y-S00YH shows a slightly higher NPV. Considering the operational benefits and profitability, hydraulic fracturing should be seriously considered for the further development of the Saadi reservoir. This comparative study provides valuable insights into the most effective approach for enhancing oil production in tight reservoirs like Saadi, balancing the technical feasibility and economic viability of different stimulation scenarios. The findings can guide decision-making processes and contribute to maximizing oil recovery in similar challenging reservoirs.