Shale Field Research Articles

Sustainable hydrogen production from flare gas and produced water: A United States case study

Gas flaring and produced water (PW) emissions are common environmental challenges with significant impacts on the oil production industry. This study proposes a novel approach to address these concerns by developing energy self-sufficient networks for simultaneous utilization of flare gas (FG) and PW for sustainable hydrogen production. Three distinct scenarios are analyzed: hydrogen production without CO2 capture (Hydra), fossil fuel-based (FF) hydrogen production with CO2 capture and utilization in enhanced oil recovery (HydraCap-FF), and a solar-thermal-assisted HydraCap-FF system (HydraCap-RE). Techno-economic and environmental models are constructed for each scenario's optimal configuration, enabling a comparative analysis of their economic viability and environmental impact. Additionally, the designed systems are examined through a flexibility analysis to evaluate input materials and their influence on the system's viability. Results highlight the promising potential of HydraCap-RE, achieving significant reductions in CO2 emissions and water footprint compared to traditional methods. The HydraCap-RE generates hydrogen with the cost of 2.86 $/kg H2, hydrogen yield of 31.25 kg H2/100 kg FG, specific emission of 0.86 kg CO2/kg H2 and water footprint of 0.185 kg H2O/kg H2. Moreover, the flexibility analysis indicates that an optimal FG/PW ratio of 0.53 yields the highest economic value. The results demonstrate that deploying HydraCap-FF in the Permian, Bakken, and Eagle Ford shale regions can produce 0.807, 0.454, and 0.121 million tons of hydrogen annually, respectively, and reduce CO2 emissions by 6.37, 3.58, and 0.956 million tons, respectively. Furthermore, the HydraCap-RE deployment in these shale fields outperformed, with 17 % higher hydrogen production and 28.42 % lower CO2 emissions. These findings provide valuable insights for decision-makers seeking to reduce CO2 emissions the oil and gas industries and providing clean and sustainable products for these areas.

Field pilots of carbon dioxide huff and puff method at a shale oil field

AbstractCO2 huff and puff is a widely used enhanced oil recovery method in many oil fields, but its implementations in shale fields is scarce. This paper reports trials of CO2 huff and puff in a shale field in China. Laboratory studies revealed that CO2 effectively reduced oil viscosity, increased oil volume, and improved oil recovery under miscible conditions. For the three wells that received CO2 huff and puff treatments, one well showed satisfactory results, while the other two wells demonstrated poor economics. Discussions and recommendations are made based on field experiences. © 2024 Society of Chemical Industry and John Wiley & Sons, Ltd.

Analysis of Fluid-Injection-Induced Seismicity Using a Dynamic Sliding Model Incorporating the Rate- and State-Dependent Friction Law

Summary Earthquakes can be triggered by fluid injection into underground formations. Fluid injection can cause large changes in the underground volume that exert stresses on nearby preexisting faults, leading to seismic activity. Assuming an increase in underground development activities in the future, our understanding of the mechanism underlying induced seismicity must be improved, and methods must be developed to properly assess the risk of seismic events. The objective of this study is to develop a seismicity prediction model that calculates the magnitude and timing of triggered earthquakes or seismic events occurring during various subsurface fluid injection activities. We developed an injection-induced seismicity analysis model that predicts the dynamic earthquake nucleation caused by changes in stress and pore pressure that occur during various subsurface activities. The governing equations consisting of the dynamic motion of the poroelastic spring-slider system, rate and state friction laws and pore pressure diffusion equation were solved using the embedded semi-implicit Runge-Kutta (SIRK) method. The dynamic sliding model was also incorporated into the finite element method (FEM) model, considering the variations in the stresses and pore pressures in the formation. A field case study was also conducted to compare the model results with typical microseismicity responses observed from hydraulic fracturing treatments in shale fields. Contrary to the popular understanding derived from Amonton’s law, the dynamic friction model revealed that a large normal stress on the fault leads to rapid sliding. A larger normal stress accumulates a large amount of elastic energy until it slips owing to fluid injection, nucleating large seismic waves. The poroelastic spring-slider model estimated reasonable microseismic magnitudes for hydraulic fracturing treatment but overestimated the time required to trigger a microseismic event under field conditions. To improve the analysis results, the poroelastic spring-slider model was coupled with a linear elastic FEM that considered the complex interplay of stress changes from hydraulic fracturing and the associated pore pressure variation in the formation. Compared with the field data, the coupled simulation model estimated a reasonable timing for the induced microseismic events when the increasing pore pressure during hydraulic fracturing penetrated deep into the formation. These findings suggest the existence of permeable natural fractures in the formation, which intensify early frictional sliding during treatment. The seismicity prediction model presented in this study simulates the magnitude and timing of seismic nucleation, helping to manage and mitigate the environmental impacts of induced seismicity during various subsurface development activities, such as oil and gas extraction, hydraulic fracturing, geothermal, and carbon dioxide sequestration. Moreover, the case study results imply that the time series of seismic events predicted by the model can be used to understand the possible fracture geometry and extent of fluid invasion for field applications. Key Terms and Phrases induced seismicity, subsurface fluid injection, rate- and state-dependent friction law, embedded semi-implicit Runge-Kutta method, finite element analysis

Reverse osmosis-based water treatment for green hydrogen production

We analyze the use of excess natural gas (currently flared/vented) to instead treat oilfield-produced water via reverse osmosis (RO) to generate ultrapure electrolysis-grade water (Total Dissolved Solids (TDS): 0.028‐0.5 ppm) for green hydrogen production. We combine an analytical ε-MTU model and CPavg model to predict average permeate concentration, to obtain improved estimates of electrolysis-grade water production from RO systems. The theoretical upper limit of the recovery of a RO system (similar to Carnot efficiency of heat engines) is established. Analysis is conducted for conditions corresponding to Niobrara Shale field (TDS: 29.1 g/L), as well as for brackish water (TDS: 5-15 g/kg) and seawater (TDS: 35–45 g/kg) feeds. Results show that electrolysis-grade water production can be as high as 0.75 m3 per cubic meter of water treated, with 1.38 m3 of natural gas providing the required energy. This translates to hydrogen production of 74.6 kg per cubic meter of produced water treated. Relatively low volumes of gas can treat large water volumes (<4 % of excess gas in Niobrara Shale can treat the entire quantity of produced water). These numbers highlight the benefits of our approach of utilizing two waste streams to create a high-value commodity, critical for decarbonization.

AI, Influencers, and Grit: How Apache’s 8-Year Quest To Build Its Own Drilling Advisor Achieved Full Adoption

When oil prices tumble, upstream research and development projects are among the first casualties. Many are put on the shelf. Few are ever taken off. Then there’s what happened at Apache Corp. More than a decade ago, the Houston-based independent oil and gas producer, which following a restructuring is now a subsidiary of APA Corp., was among a small cadre of operators working at the fore of automated drilling technology. As a first adopter, Apache had gone so far as to develop a newbuild automated rig design for its onshore shale fields in Texas. Then in mid-2014, crude prices plummeted nearly 60% over a 7-month period. The heady days of $100/bbl oil were replaced by the era of “lower for longer,” derailing Apache’s ambitious plan to build its pioneering prototype. That could have been the end of the story. But less than a year after the ambitious capital project was scrapped, something else emerged in its place. While AI-based automation was out, Apache’s drilling team was given a chance to develop the next best thing: an AI-based drilling advisory system. “We saw that there was at least a small opportunity to do something more with our rig data—that 1-Hz real-time data—by combining it and mashing it up with contextual data so that it could be something useful,” said Michael Behounek, a former director of drilling, completions, and workover performance and leader of the project for Apache where he spent the past 13 years before taking early retirement. Now a managing partner of an upstream digital consulting startup called Emerja, Behounek spoke at the recent SPE Annual Technical Conference and Exhibition while presenting SPE 215132. The paper outlines how after 8 years that small opportunity turned into a 10% year-over-year reduction in drilling costs. The system, a presumed multi-million dollar value creator, was adopted across all of Apache’s contracted rigs in 2018, playing an increasingly important role in the drilling of more than 1,700 wells across a wide spectrum of geologies. This track record spans nine onshore and offshore basins, with deployments of the system in the Permian Basin, Egypt, Canada, offshore Suriname, and the North Sea. Behounek said most of the reported cost savings stem from the models’ ability to trim rig time by predicting problems that would keep drillers from staying on bottom and turning to the right. That said, the paper, which is coauthored by Apache’s software partner Intellicess Inc., emphasizes that “the system only enables the opportunity—it is the field personnel and engineers taking the proper actions and decisions offered by the system that deliver the improvement.” Apache has shared several papers about the various components of the advisory program over the years but the most recent offers a holistic view of the strategy that led to companywide adoption. Of the dozens of takeaways it offers, some of the biggest follow.

Interfacial Adsorption Kinetics of Methane in Microporous Kerogen.

Rapid declines in unconventional shale production arise from the poorly understood interplay between gas transport and adsorption processes in microporous organic rock. Here, we use high-fidelity molecular dynamics (MD) simulations to resolve the time-varying adsorption of methane gas in realistic organic rock samples, known as kerogen. The kerogen samples derive from various geological shale fields with porosities ranging between 20% and 50%. We propose a kinetics sorption model based on a generalized solution of diffusive transport inside a nanopore to describe the adsorption kinetics in kerogen, which gives excellent fits with all our MD results, and we demonstrate it scales with the square of the length of kerogen. The MD adsorption time constants for all samples are compared with a simplified theoretical model, which we derive from the Langmuir isotherm for adsorption capacitance and the free-volume theory for steady, highly confined bulk transport. While the agreement with the MD results is qualitatively very good, it reveals that, in the limit of low porosity, the diffusive transport term dominates the characteristic time scale of adsorption, while the adsorption capacitance becomes important for higher pressures. This work provides the first data set for adsorption kinetics of methane in kerogen, a validated model to accurately describe this process, and a qualitative model that links adsorption capacitance and transport with the adsorption kinetics. Furthermore, this work paves the way to upscale interfacial adsorption processes to the next scale of gas transport simulations in mesopores and macropores of shale reservoirs.

Finite Element and Neural Network Models to Forecast Gas Well Inflow Performance of Shale Reservoirs

Shale gas reservoirs are one of the most rapidly growing forms of natural gas worldwide. Gas production from such reservoirs is possible by using extensive and deep well fracturing to contact bulky fractions of the shale formation. In addition, the main mechanisms of the shale gas production process are the gas desorption that takes place by diffusion of gas in the shale matrix and by Darcy’s type through the fractures. This study presents a finite element model to simulate the gas flow including desorption and diffusion in shale gas reservoirs. A finite element model is used incorporated with a quadrilateral element mesh for gas pressure solution. In the presented model, the absorbed gas content is described by Langmuir’s isotherm equation. The non-linear iterative method is incorporated with the finite element technique to solve for gas property changes and pressure distribution. The model is verified against an analytical solution for methane depletion and the results show the robustness of the developed finite element model in this study. Further application of the model on the Barnett Shale field is performed. The results of this study show that the gas desorption in Barnett Shale field affects the gas flow close to the wellbore. In addition, an artificial neural network model is designed in this study based on the results of the validated finite element model and a back propagation learning algorithm to predict the well gas rates in shale reservoirs. The data created are divided into 70% for training and 30% for the testing process. The results show that the forecasting of gas rates can be achieved with an R2 of 0.98 and an MSE = 0.028 using gas density, matrix permeability, fracture length, porosity, PL (Langmuir’s pressure), VL (maximum amount of the adsorbed gas (Langmuir’s volume)) and reservoir pressure as inputs.

Paleo-environmental study of the Raniganj and Barakar Formations: Implications from the Geochemical and Geomechanical Aspects of Sandstone and Shale

ABSTRACT The study considers the impact of the degree of weathered material constituting the sedimentary rocks on the strength of the Lower Gondwana coal measure rocks. The dependence of the strength of primary rocks on the alteration indices has been previously studied, but it is unknown for secondary/ sedimentary rocks. Therefore, in this paper, Lower Gondwana coal measure rocks (sandstone and shale) from the most productive coalfields of India, the Barakar and Raniganj coalfields, have been studied geochemically and geomechanically to find out their correlation. Geochemically, the study revealed that an arid, non-marine, and deltaic depositional environment prevailed during the sedimentation of Barakar and Raniganj Formations. The provenance was deduced to be mafic igneous. It was also deduced that the Lower Gondwana sandstone is clay-rich, and the sandstone samples fall in the shale field in the chemical classification scheme for terrigenous clastic sediments. The weathering indices, along with the uniaxial compressive strength (UCS) of the Barakar and Raniganj Formation coal measure rocks, have been assessed. The dependence of UCS on the weathering indices has been evaluated, and positive relationships were obtained.

Water Imbibition and Oil Recovery in Shale: Dynamics and Mechanisms Using Integrated Centimeter-to-Nanometer-Scale Imaging

Summary Water imbibition, and the associated oil displacement, is an important process in shale oil reservoirs after hydraulic fracturing and in water-based enhanced oil recovery (EOR). Current techniques for water imbibition measurement are mostly “black-box”-type methods. A more explicit understanding of the water imbibition/oil recovery dynamics and geological controls is in demand. In this paper, a multiscale imaging technique that covers centimeter to nanometer scale (i.e., core to pore scale), integrating neutron radiography, microcomputed tomography (micro-CT), and scanning electron microscope (SEM) is applied to investigate the water imbibition depth and rate and the cause of heterogeneity of imbibition in shale samples. The dynamic processes of water imbibition in the 1-in. (25.4-mm) core sample were explicitly demonstrated, and the imbibition along the matrix and imbibition through microfractures are distinguished through neutron radiography image analysis. The causes of observed imbibition heterogeneity were further investigated through micro-CT and SEM image analysis for 1.5-mm diameter miniplug samples from different laminas of the 1-in. core samples. Imbibition depth and rate were calculated on the basis of image analysis as well. Estimation of oil recovery through water imbibition in shale matrix was performed for an example shale field. This innovative and integrated multiscale imaging technique provides a “white/gray-box” method to understand water imbibition and water-oil displacement in shale. The wide span of the length scale (from centimeter to nanometer) of this technique enables a more comprehensive, accurate, and specific understanding of both the core-scale dynamics and pore-scale mechanisms of water imbibition, oil recovery, and matrix-fracture interaction.

A flexible and scalable model to improve decision quality in shale plays

Shale asset investment decisions are difficult to model because they are portfolios of options under complex and time-evolving uncertainties. Sequential development decisions must balance short-term cash flow with long-term value creation. Typical assets consist of thousands of locations, making exact analysis impossible. Consequently, decision support tools are very simple, usually consisting of decision trees, fixed price decks, and no midstream constraints.We develop a heuristic that maps the current information of an asset, such as inventory, prices, and estimated production, to a well schedule. We combine the heuristic with Monte Carlo simulation and decision trees to form a shale field development model that includes all relevant features while being scalable to realistic problem sizes. To demonstrate our method's performance, we create a sample shale asset with 370 wells, price and production uncertainty, midstream constraints, and 30 decision periods. On the sample problem, our method exhibits first-order stochastic dominance over the decision tree approach and improves expected value by 407%. Using our modeling approach will improve overall decision quality in shale asset management.

Mechanisms of Casing Deformation during Hydraulic Fracturing in the Horizontal Wells of the Weirong Shale Field.

Casing deformation is frequent during hydraulic fracturing in the Weirong shale gas field, which impedes shale gas production. We investigated the effect of shale elastic modulus on casing deformation based on shale swelling in this work. According to field data, the silicon content in the Weirong shale gas field has a considerable impact on casing deformation during hydraulic fracturing. Furthermore, the results of the experiment show that the silicon content is positively related to the elastic modulus of shale. We conducted numerical simulations to analyze the casing deformation based on shale swelling. We observed that the shale elastic modulus was negatively correlated with the casing stress without shale swelling; however, the shale elastic modulus was positively correlated to casing stress with shale swelling. Furthermore, when the elastic modulus remained constant, casing stress was positively correlated with shale swelling. The numerical simulation results were validated using field data from the WY23-5 shale well. Moreover, factors such as injection pressure, formation pressure, and cement sheath elastic modulus can increase the impact of the shale elastic modulus on casing deformation with shale swelling. Casing deformation is greatly influenced by the distribution of the stimulated reservoir volume (SRV) area. Different SRV area behaviors result in different types of casing deformation. The symmetric distribution of the SRV area causes casing extrusion deformation, whereas the asymmetric distribution of the SRV area causes casing bending deformation. Moreover, casing stress is positively correlated with the length of the SRV area.

Method to account for natural fracture induced elastic anisotropy in geomechanical characterization of shale gas reservoirs

Shale has been usually recognized as a transverse isotropic (TI) medium in conventional geomechanical log interpretation due to its laminated nature. However, when natural fractures exist in the shale rock, additional elastic anisotropy is introduced, converting laminated Shale to an orthorhombic (OB) medium. Previous studies illustrate that neglecting the natural fracture induced anisotropy in shale geomechanical log interpretation could lead to inaccurate evaluations of elastic moduli and in-situ stresses.In this paper, a new method is developed to account for the natural fracture induced anisotropy in geomechanical log interpretation based upon the TI acoustic model developed by the author and a characterization technique of elastic wave anisotropy (Sayers, 1991). The new OB model incorporates the four acoustic log data inputs and five modeling constraints in a nonlinear optimization algorithm to solve for the nine independent stiffness coefficients of an OB rock, and further to solve for the geomechanical properties and in-situ stress profiles in an OB formation.The new method was validated with a Marcellus Gas Shale field case. Both the new OB model and the conventional TI model were applied to interpret the minimum horizontal stress profile for the same formation. By comparing the results, the OB model is more robust than the TI from two aspects. First, the average stress magnitude predicted by the OB model is closer to the one measured by the Diagnostic Fracture Injection Test (DFIT). Second, the OB model predicts a more obvious stress barrier between the lower Marcellus and upper Onondaga Limestone than the TI model does. The predicted stress barrier is consistent with the observation of the microseismic events of a horizontal well drilled and completed nearby, which reveals that no hydraulic fracture propagates downward through the bottom boundary of Marcellus Shale into the underlying Onondaga Limestone.

Investigation of sorptive interaction between phosphonate inhibitor and barium sulfate for oilfield scale control

In both offshore deepwater and shale fields, a large amount of produced water will be generated during field operations. One consequence of significant produced water production from the field is mineral scale formation. Barium sulfate (barite) is one of the toughest scales to manage in oilfield. To combat scale issues, scale inhibitor has been widely adopted to inhibit scale deposition. Previous studies have confirmed that sorptive interactions between chemical inhibitor and scale particles play a vital role in scale prevention and control. Although extensive studies have been carried out on inhibitor-scale interaction, a comprehensive understanding of inhibition is yet available and the detailed sorptive interaction between inhibitor and mineral scale is not fully understood. In this study, experimental efforts have been made to explore the governing mechanism of sorptive behavior of a common phosphonate inhibitor onto the surface of barite particles. Adsorption and desorption experiments involving phosphonate and barite were carried out over a wide range of physiochemical conditions in a systematic manner. It shows that both adsorption and desorption of inhibitor to and from barite surfaces proceed rapidly. At a low phosphonate concentration, surface adsorption mechanism accounts for the interaction between phosphonate and barite. The release of phosphonate inhibitor from the barite surface is controlled by the dissolution dynamics of the formed Ca-phosphonate precipitate. This study is the first report of investigation of barite with phosphonate inhibitor with low and ultra-low concentrations as well as the inhibitory mechanism. The obtained results will improve our understanding of the interaction between phosphonate inhibitors and mineral scale. The findings can provide fundamental information that can benefit the inhibition performance and efficiency for barite scale control in oilfield operations.

A deep-learning-based prediction method of the estimated ultimate recovery (EUR) of shale gas wells

The estimated ultimate recovery (EUR) of shale gas wells is influenced by many factors, and the accurate prediction still faces certain challenges. As an artificial intelligence algorithm, deep learning yields notable advantages in nonlinear regression. Therefore, it is feasible to predict the EUR of shale gas wells based on a deep-learning algorithm. In this paper, according to geological evaluation data, hydraulic fracturing data, production data and EUR evaluation results of 282 wells in the WY shale gas field, a deep-learning-based algorithm for EUR evaluation of shale gas wells was designed and realized. First, the existing EUR evaluation methods of shale gas wells and the deep feedforward neural network algorithm was systematically analyzed. Second, the technical process of a deep-learning-based algorithm for EUR prediction of shale gas wells was designed. Finally, by means of real data obtained from the WY shale gas field, several different cases were applied to testify the validity and accuracy of the proposed approach. The results show that the EUR prediction with high accuracy. In addition, the results are affected by the variety and number of input parameters, the network structure and hyperparameters. The proposed approach can be extended to other shale fields using the similar technic process.

Enhanced Oil Recovery Method Selection for Shale Oil Based on Numerical Simulations.

As unconventional reserves, oil shale deposits require additional oil recovery techniques to achieve favorable production levels. The efficiency of a shale reservoir development project is highly dependent on the application of enhanced oil recovery (EOR) techniques. There are many studies devoted to discrete investigations of each EOR method. Most of them claim that one particular method is particularly effective in increasing oil recovery. Despite the wealth of such research, it remains hard to say with certainty which technique would be the most effective when applied in the extraction of unconventional reserves. In this work, we aim to answer this question by means of a comparative study. Three EOR methods were applied and analyzed in the same environment, a single target object—an oil field in Western Siberia characterized by ultra-low permeability (0.03 mD on average) and high organic content. Methods involving huff-and-puff injection of a surfactant solution, hydrocarbon gas, and hot water were studied using numerical reservoir simulations based on preceding laboratory experiments. A single horizontal well having undergone nine-stage hydraulic fracturing was used as the field site model. The comparative calculations of cumulative oil production over an 8-year period revealed that the injection of hot (supercritical) water led to the highest oil recovery in the target shale reservoir. Each EOR method was implemented using the best operation scenario. All three cases resulted in an increase in cumulative oil production compared to the depletion mode, though the efficiency was distinctly different. Twenty-six percent more oil was obtained after hot water injection, 16% after hydrocarbon gas, and 12% after a surfactant solution. Simulation of a hot water huff-and-puff operation over a longer period (43 years) led to a level of oil production 3 times higher than depletion. The drawbacks of each EOR method on the shale site are discussed in the results. A possible solution was proposed for preventing the negative effects of heat loss and water blockage incurred from hot water injection. The comparative study concludes that hot water injection should lead to the highest volume of oil recovery. The conclusions drawn are suggested to be relevant for similar shale fields.

Assessing Hydraulic Fracking Issues in the US South East and Western Region

In the last several years, the choice of hydrological fracking as an alternative method of nonrenewable energy production in the US oil sector continues to gain currency across regions especially the Southeast and the West. In a country where fracking is no longer deemed as an exercise on the fringe amidst unprecedented expansion, economic boom, and ecological liabilities. The use of fracking techniques in shale fields remains so widespread across different states from California to Mississippi that it now constitutes 60% of the nation’s oil and gas output in the past two decades. This occurred in the face of favorable regulatory environments that catapulted the US atop global ranking of oil producers. While this has resulted in ample generation of revenues and job prospects in the respective states, communities in those places have endured grim impacts and risks on their ecosystems in the form of pollution, degradation, hydrological stress, induced seismicity, land disturbance and greenhouse gas emissions. Aside from efforts of the sector, regulatory agencies, and other stakeholders in the search for a common ground on the issues. The mounting ecological liabilities has in many cases aggravated tensions between affected communities and the oil sector. Yet, very little studies exist on the vulnerability of the study area to the impacts of hydraulic fracking using mix scale method of Geographic Information Systems (GIS) and energy statistics. Even when data is available, the sketchy nature tends to mar analytical proficiency given the lack of an accessible regional energy information system. Accordingly, this enquiry will fill that void by assessing the issues in hydraulic fracking in the study area. Emphasis are on the issues, trends, factors, impacts and efforts using techniques of GIS and descriptive statistics. Just as the results revealed a surge in production activities and revenues, the impacts consist of sizable use of water and chemicals together with extensive pollution, the disturbance of fragile landscapes and ecosystem decline. Additionally, GIS mappings pinpointed a gradual spread of production activities and concentration of risks across states in the zone due to several socio-economic and physical elements located withing the larger energy structure. To remedy the situation, the paper proffered solutions ranging from ecological monitoring to the design of a regional energy information system, effective policy, community participation/education of the public and the formation of an interagency task force.

Technology Focus: Unconventional and Tight Reservoirs (July 2021)

As unconventional oil and gas fields mature, operators and service providers are looking toward, and collaborating on, creative and alternative methods for enhancing production from existing wells, especially in the absence of, or at least the reduction of, new well activity. While oil and gas price environments remain uncertain, recent price-improvement trends are supporting greater field testing and implementation of innovative applications, albeit with caution and with cost savings in mind. Not only is cost-effectiveness a requirement, but cost-reducing applications and solutions can be, too. Of particular interest are applications addressing challenging well-production needs such as reducing or eliminating liquid loading in gas wells; restimulating existing, underperforming wells, including as an alternative to new well drilling and completion; and remediating water blocking and condensate buildup, both of which can impair production from gas wells severely. The three papers featured this month represent a variety of applications relevant to these particular well-production needs. The first paper presents a technology and method for liquid removal to improve gas production and reserves recovery in unconventional, liquid-rich reservoirs using subsurface wet-gas compression. Liquid loading, a recurring issue downhole, can severely reduce gas production and be costly to remediate repeatedly, which can be required. This paper discusses the full technology application process and the supportive results of the first field trial conducted in an unconventional shale gas well. The second paper discusses the application of the fishbone stimulation system and technique in a tight carbonate oil-bearing formation. Fishbone stimulation has been around for several years now, but its best applications and potential have not necessarily been fully understood in the well-stimulation community. This paper summarizes a successful pilot application resulting in a multifold increase in oil-production rate and walks the reader through the details of the pilot candidate selection, completion design, operational challenges, and lessons learned. The third paper introduces and proposes a chemical treatment to alleviate phase trapping in tight carbonate gas reservoirs. Phase trapping can be in the form of water blocking or increasing condensate buildup from near the wellbore and extending deeper into the formation over time. Both can reduce relative permeability to gas severely. Water blocks can be a one-time occurrence from drilling, completion, workover, or stimulation operations and can often be treated effectively with solvent plus proper additive solutions. Similar treatments for condensate banking in gas wells, however, can provide only temporary alleviation, if they are even effective. This paper proposes a technique for longer-term remediation of phase trapping in tight carbonate gas reservoirs using a unique, slowly reactive fluid system. Recommended additional reading at OnePetro: www.onepetro.org. SPE 200345 - Insights Into Field Application of Enhanced-Oil-Recovery Techniques From Modeling of Tight Reservoirs With Complex High-Density Fracture Network by Geng Niu, CGG, et al. SPE 201413 - Diagnostic Fracture Injection Test Analysis and Simulation: A Utica Shale Field Study by Jeffery Hildebrand, The University of Texas at Austin, et al.

A Mathematical Model for Estimating Fracture Permeability with Invasion Damage of Formation Sand

Summary Fracture packing is a well-known completion technique used in the hydraulic fracturing of low-permeability reservoirs. As much as fracture packs are very effective, the proppant-pack permeability damage formed from particle intrusion reduces that effectiveness because it causes low well productivity. It is important to address the issue of permeability damage caused by formation-particle intrusion. An analytical model was developed in this study to predict the permeability of proppant packs in hydraulic fractures with consideration of different levels of invasion damage of formation sand. The accuracy of the model was verified by model comparison with data from the Eagle Ford Shale field. The model result shows that for the Eagle Ford field and the corresponding proppant size used, three blocking levels were achieved that correspond to high proppant-pack permeability. Three case studies were considered in this study: California sand, Gulf Coast sand, and South China Sea silt. The proppant-pack permeability damage was calculated using the analytical model for three levels of invasion for all case studies. The results from applying the analytical model on the three case studies showed the amount of invasion that is possible in each sand according to the proppant size used. The level of invasion is a factor of the sand distribution and the initial proppant size chosen. More analysis showed that for two of the case studies, only Levels 1 and 2 blockings can develop, while for the last case study, three blocking levels considered can develop. This study, for the first time, gives an insight into how selecting the optimal proppant size can improve sand-control performance while enhancing fracture conductivity.

An analytic model for computing the countercurrent flow of heat in tubing and annulus system and its application: Jet pump

Shale fields are currently over-reliant on electric submersible pumps (ESPs) in the early stage of artificial lift despite its weakness to sandy flow and often failing within the first three months. Jet pumps are reliable and cost-effective alternatives to the ESPs. Current studies on jet pumps have focused on designing parameters for maximizing performance; however, there have been very few investigations on predicting temperature profiles in the wellbore with a jet pump in use. Fluid temperature influences viscosity; hence, the production of heavy oil. Typically, the heavier the hydrocarbon, the greater is the variation in viscosity with temperature. Therefore accurate temperature prediction is essential for the efficient design of heavy oil production facilities. This paper offers an analytic model to compute temperature profiles in the tubing and annulus. Results show a good match with a field data set.Data set from a well in Tah field in China is used to validate the model. In addition, sensitivity analyses were performed that showed that injection temperature affects the annulus temperature profile, leading to significant changes in frictional pressure loss at shallow depths. In contrast, injection rate has less influence on temperature profiles, although, of course, higher fluid velocity causes greater frictional losses. Results show that a hotter and relatively small flow rate leads to lesser pumping cost by reducing frictional pressure drop during the operation.The proposed model ideally requires the bottom-hole temperature as a boundary condition (BC). When subsurface temperature data are unavailable, as often the case due to cost, a computing method is offered in the paper for reliable temperature profile estimation from only two data points at the wellhead.

China’s Unconventional Challenge Spurs New Thinking on Shale and Tight Reservoirs

Despite possessing some of the world’s largest shale-gas resources, China is likely in 2020 to have produced less than half of the 30 Bcm per year in shale gas that the government set as a goal in its latest Five-Year Plan. While such a small volume may make shale production seem inconsequential to China’s overall energy balance, it is clear that when it comes to developing unconventional hydrocarbons, China is playing a long game. With regard to shale alone, a 2013 US Energy Information Administration study noted that China has the world’s second-largest technically recoverable shale-gas resources at an estimated 1,115 Tcf; the US is first with 1,161 Tcf. Even more to the point, China is one of only four countries (including the US, Canada, and Argentina) that produce commercial volumes of both shale gas and of tight oil. But it is the lack of efficient technologies and infrastructure that stand in the way of China besting the US and creating its own “shale revolution.” China’s most attractive reserves occur in remote, mountainous areas where, in some cases, shale resources can lie as deep as 3500 m. In separate papers presented in October during the 2020 SPE Russian Petroleum Technology Conference, the China National Petroleum Company (CNPC) detailed new technologies it is applying to meet some of these challenges. Paper SPE 202066, coauthored by subsidiaries of CNPC, Downhole Service Company and CCDC Petroleum Drilling &amp; Technology Company Ltd., details the application of enhanced-hydraulic- fracturing technology (EHFT) to raise the effective stimulated reservoir volume (SRV) in the Sichuan shale basin. A second paper (SPE 202062), coauthored by CNPC and Halliburton, offers a case study in tight-oil production in Daqing employing an intensive fracture-cluster-completion strategy using a microemulsion flowback technology. The Spice in Sichuan Shale China boasts three shale basins (Sichuan, Tarim, and Yantze), but its principal development focus is in the southwestern province of Sichuan, which holds half of the country’s shale reserves. In developing fields such as Weiyuan, Changning, and Jiaoshiba, producers target the Ordovician Wufeng-Silurian Longmaxi formation. The total proved geological reserves of these three gas fields exceeds 500 Bcm, the authors noted in their paper. To develop infrastructure supporting industrial-scale operations and to introduce and test new technologies to raise shale output, China has established several national pilot demonstration areas. One of those is the Weiyuan national shale demonstration area in south Sichuan, where the authors quote an annual production of 2.5 Bcm. Staged horizontal fracturing is the main technology used at Weiyuan and other Chinese shale fields as producers strive to expand the fracture extension area, increase the reconstruction volume, and improve the productivity of single wells. An analysis of production data from Weiyuan showed, however, that the long-term conductivity of fractures is limited because the length and height of supporting fractures are short. Thus, because of the limited volume of reconstruction, production decreases rapidly and efficiency suffers as pressure declines.