Shale Wells Research Articles

Coupled laboratory and field investigations resolve microbial interactions that underpin persistence in hydraulically fractured shales

Hydraulic fracturing is one of the industrial processes behind the surging natural gas output in the United States. This technology inadvertently creates an engineered microbial ecosystem thousands of meters below Earth's surface. Here, we used laboratory reactors to perform manipulations of persisting shale microbial communities that are currently not feasible in field scenarios. Metaproteomic and metabolite findings from the laboratory were then corroborated using regression-based modeling performed on metagenomic and metabolite data from more than 40 produced fluids from five hydraulically fractured shale wells. Collectively, our findings show that Halanaerobium, Geotoga, and Methanohalophilus strain abundances predict a significant fraction of nitrogen and carbon metabolites in the field. Our laboratory findings also exposed cryptic predatory, cooperative, and competitive interactions that impact microorganisms across fractured shales. Scaling these results from the laboratory to the field identified mechanisms underpinning biogeochemical reactions, yielding knowledge that can be harnessed to potentially increase energy yields and inform management practices in hydraulically fractured shales.

Numerical representation of multi-component gas flow in stimulated shale reservoirs

Unlike conventional or tight gas reservoirs, shale gas or oil reservoirs have complex fracture networks that are often developed due to the interactions between natural and hydraulic fractures. Another major characteristic of shale reservoirs is that a good portion of shale gas can be in adsorbed state. In order to capture these characteristics of shale reservoirs numerically, PSU-SHALECOMP, a compositional dual-porosity, dual-permeability, multi-phase reservoir simulator is employed together with the implementation of stimulated reservoir volume (SRV) approach. In this approach, three of the reservoir parameters are altered to define hydraulic fractures in the form of SRV. These altered properties are SRV fracture permeability, SRV fracture porosity and SRV fracture spacing. In the validation phase of these computationally inexpensive SRV models, rock and fluid properties and reservoir conditions representative of a Marcellus shale reservoir and normalized field data from Marcellus shale wells to history-match the production performances were used. It is shown that the PSU-SHALECOMP simulator with the implementation of SRV model is capable of matching the historical data effectively and rapidly. In pursuit of successful validations of various production scenarios, several carbon dioxide injection scenarios were performed to see the performance of the PSU-SHALECOMP simulator in depleted Marcellus shale reservoirs.

Study on the influence of elastic modulus heterogeneity on in-situ stress and its damage to gas shale reservoirs

Shale heterogeneity has a significant effect on drilling and completions, hydraulic fracturing, as well as hydrocarbon development performance. However, it lacks representation of rock damage/failure caused by the mechanical heterogeneity and “stress shadow” effect during the hydraulic fracturing process. In this paper, the Galerkin finite element method was adopted to numerically simulate the hydro-mechanical coupled interaction based on the solver in the COMSOL Multiphysics software and Matlab scripting development. The Weibull probability density function was used to represent the mechanical heterogeneity of gas shale. Under the condition of fully fluid-solid coupling during the fracking process, the effect of mechanical heterogeneity on von – Mises stress, strain energy density, damage factor, and fluid pressure was numerically simulated in the gas shale wells. The curves of von – Mises stress, strain energy density, and damage factor along a certain straight line showed the obvious decreasing distribution in a completely homogeneous formation. As the strata are heterogeneously enhanced, their distribution curves showed fluctuations. Moreover, von – Mises stress and strain energy density had a good relationship with damage factors. Accordingly, the method of rock damage/fracture and "stress shadow" effect caused by mechanic heterogeneity was put forward under the circumstance of two–dimensional plane strain. That was to use, the von – Mises stress or strain energy density at the single point or line to characterize the degree of local rupture or the shadow effect of stress, and the average strain energy density per unit area to characterize the degree of rupture of the rock or the intensity of the shadow effect. The study is of great significance to further improve the SRV(Stimulated Reservoir Volume) fracturing design and the productivity of gas shale wells.

Price Elasticity of Supply and Productivity: An Analysis of Natural Gas Wells in Wyoming

Using a large dataset of well-level natural gas production from Wyoming, we evaluate the respective roles played by market signals and geological characteristics in natural gas supply. While we find well-level production of natural gas is primarily determined by geological characteristics, producers respond to market signals through drilling rates and locations. Using a novel fixed effects approach based on petroleum-engineering characteristics, we confirm that production decline rates tend to be larger for wells with larger peak-production rates. We also find that the price elasticity of peak production is negative, plausibly because firms drill in less productive locations as prices increase. Finally, we show that drilling is price inelastic, although the price elasticity of drilling increased significantly when new technologies began to be adopted in Wyoming. Our results indicate that the popular view that shale wells have larger decline rates than conventional wells can be at least partially explained by the pattern of falling natural gas prices.

Shale gas resources of the Bowland Basin, NW England: a holistic study

New data from three shale gas exploration wells in the Bowland Basin of NW England contribute to the understanding of the stratigraphy, tectonic history and unconventional hydrocarbon resource potential of Lower Carboniferous strata. Three main prospective shales dominate the identified unconventional reservoirs: the Upper Bowland and Lower Bowland shales and the Hodder Mudstone, which are recognized by their distinctive lithology, corresponding log signatures and key zonal ammonoids. With a combined thickness of over 5000 ft ( c. 1500 m), this sequence of shales is one of thickest known potential self-sourced, unconventional hydrocarbon resources. The strata are organic rich with total organic carbon (TOC) values of between 1 and 7%, with an average of 2.65%, and organic maturity that ranges from the upper oil window (pyrolysis T max c . 450°C) in the higher part of the section to dry gas (R o = 2.4%; pyrolysis T max >470°C) in the Lower Bowland Shale. The sequence is strongly heterolithic, and up to 60% free gas is stored in thinly bedded carbonate and clastic silty turbidites. Adsorbed gas is concentrated in more organic-rich, hemipelagic shales which are distributed throughout the sequence. Near maximum burial temperatures of c. 130°C are inferred from vitrinite reflectance (R o ) and are consistent with fluid-inclusion microthermometry of carbonate-filled fractures. This indicates oil generation in the Late Carboniferous, prior to Variscan uplift. Renewed subsidence through the early Mesozoic resulted in increased maturity and gas generation. In the Bowland Shale the gas per unit volume of rock ranges from about 0.6 to 1.5 Bcf (billion cubic ft) per metre per square mile. The thick interval of gas-charged strata provides the opportunity to exploit these major hydrocarbon resources by using stacked multilateral wells from a common, strategically located and environmentally optimized surface pad.

Field data provide estimates of effective permeability, fracture spacing, well drainage area and incremental production in gas shales

About half of US natural gas comes from gas shales. It is valuable to study field production well by well. In early 2018, there were some 67,000 active horizontal gas shale wells in the US, some more than 12 years on production. Our approach is a hybrid between an unstructured big-data approach and physics-based models. We extend a previous two-parameter scaling theory of shale gas production by adding a third parameter that incorporates gas inflow from the external unstimulated reservoir. This allows us to estimate for the first time the effective permeability of the unstimulated shale and the spacing of fractures in the stimulated region. From an analysis of wells in the Barnett shale, we find that on average stimulation fractures are spaced every 20 m, and the effective permeability of the unstimulated region is 100 nanodarcy. We estimate that over 30 years on production the Barnett wells will produce on average about 20% more gas because of inflow from the outside of the stimulated volume. There is a clear tradeoff between production rate and ultimate recovery in shale gas development. In particular, our work has strong implications for well spacing in infill drilling programs.

Shale Gas Well, Hydraulic Fracturing, and Formation Data to Support Modeling of Gas and Water Flow in Shale Formations

AbstractThe potential for shale gas development and hydraulic fracturing to cause subsurface water contamination has prompted a number of modeling studies to assess the risk. A significant impediment for conducting robust modeling is the lack of comprehensive publicly available information and data about the properties of shale formations, shale wells, the process of hydraulic fracturing, and properties of the hydraulic fractures. We have collated a substantial amount of these data that are relevant for modeling multiphase flow of water and gas in shale gas formations. We summarize these data and their sources in tabulated form.

Hydraulic Fracturing: Fracturing Plans and Reality Often Look Really Different

Fracturing Plans and Reality Often Look Really Different Stephen Rassenfoss, JPT Emerging Technology Senior Editor and Matt Zborowski, JPT Technology Writer Good diagnostic testing is often painstaking, time-consuming, and costly, but recent studies suggest that a lack of knowledge can be even costlier. According to several recent technical papers, hydraulic fracturing often misses its target, and productive early wells in stacked plays may be the template for development plans that leave a lot of hydrocarbons stranded. Shell, Devon, and Anadarko have deployed multiple tools in the field because “no single fracture diagnostic can answer all the questions,” said Gustavo Ugueto, senior staff petrophysical engineer for Shell, during a presentation at the recent SPE Hydraulic Fracturing Technical Conference, where all these papers were presented. Hydraulic Fracturing Going Sideways Stephen Rassenfoss, JPT Emerging Technology Senior Editor Fracturing plans offer a vision of high-pressure slurries of water and sand shooting out of each perforation creating a dense, even array of fractures around a wellbore. Getting More out of Stacked Zones Stephen Rassenfoss, JPT Emerging Technology Senior Editor An early well that is a prolific producer can be a poor model for future drilling within a play with stacked zones. The potential downside is that strong early flow may be depleting multiple zones. Production from later wells drilled nearby is likely to suffer because the stimulated rock is in competition with older wells that have reduced both the oil and gas present, and the pressure needed for production. Seeking Insights in Microbes, DNA, and Rocks Matt Zborowski, JPT Technology Writer Anadarko Petroleum is building an expanding database of microbe DNA to help it map fluid movements and the source of production in the Delaware Basin. Erosion as a Fracturing Indicator Stephen Rassenfoss, JPT Emerging Technology Senior Editor It is common knowledge that some perforations take much of the fluid and grow into large fractures while other openings along the well never grow at all. There is no way to image the path followed by the individual cracks created by hydraulic fracturing but it is possible to see where they start. The big ones likely grew from perforations where the grinding force of the high pressure slurries of water and sand injected for fracturing have turned carved, round holes into large, often-jagged openings. Digging Up New Information On What Fractures Really Look Like Stephen Rassenfoss, JPT Emerging Technology Senior Editor During a panel discussion on what fractures look like, one expert added a significant qualifier to the title: what they “may look like.” That addition by Roberto Suarez- Rivera, scientific advisor for W.D. Von Gonten & Co., was in keeping with a discussion at the SPE Hydraulic Fracturing Technology Conference that offered ample evidence that when hydraulic fracturing is closely examined, results often vary from expectations. They Are Not Drilling Shale Wells Like They Used To Stephen Rassenfoss, JPT Emerging Technology Senior Editor Maintaining production in the shale business is getting increasingly costly because new wells in major US shale plays are falling short of output from the parent wells. A study of 10 major US basins by Schlumberger (SPE 189875) found that while the parent and child wells looked comparable at first glance—about half of new wells outperform the older wells and vice versa—the picture changes when the results are adjusted for the higher cost of drilling and fracturing new wells.

Marcellus Shale model stimulation tests and microseismic response yield insights into mechanical properties and the reservoir discrete fracture network

We have developed stimulation tests of a model discrete fracture network (DFN) in the Marcellus Shale reservoir, Morgantown, West Virginia. The microseismic response observed from the modeled stage is characteristic of that observed in several stages along the length of the horizontal well, so that the workflow developed in this paper can be easily extended to other stages in this and other Marcellus Shale wells. The model DFN is designed using log data, including fracture image logs from vertical pilot and horizontal wells. Data from these wells provide geomechanical properties, fracture trend and intensity, and stress orientation. Microseismic cluster trends provide additional constraints on geomechanical model development. Results from stimulation tests are used to modify the reservoir DFN and geomechanical model. Modifications ensure consistency with borehole observations. Fractures observed along the length of the horizontal well consist predominantly of one set, whereas two sets are observed in the vertical pilot well. These two sets are required in the model DFN to reproduce the stimulation trend inferred from microseismic data. Northeast asymmetry in the microseismicity associated with hydraulic fracture treatment is interpreted to result from a horizontal drop of [Formula: see text] toward a previously drilled well. The asymmetry is interpreted to result from stress reduction associated with treatment of an earlier parallel well, the presence of a cross-strike structure parallel to the well, or a combination of the two. Limited downward growth, inferred from the microseismic response, required an increase of the minimum stress in model strata underlying the Marcellus.

Well-Performance Study Integrates Empirical Time/Rate and Time/Rate/Pressure Analysis

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 179119, “A Well-Performance Study of Eagle Ford Gas Shale Wells Integrating Empirical Time/Rate and Analytical Time/Rate/Pressure Analysis,” by A.S. Davis and T.A. Blasingame, Texas A&M University, prepared for the 2016 SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, USA, 9–11 February. The paper has not been peer reviewed. The purpose of the complete paper is to create a performance-based reservoir characterization by use of production data (measured rates and pressures) from a selected gas-condensate region within the Eagle Ford Shale. The authors use modern time/rate (decline-curve) analysis and time/rate/pressure (model-based) analysis methods to analyze, interpret, and diagnose gas-condensate well-production data. Reservoir and completion properties are estimated; these results are then correlated with known completion variables. The time/rate and time/rate/pressure analyses are used to forecast future production and to estimate ultimate recovery. Production-Analysis Work Flow The data required for the completion of the proposed methodology include well-history files, daily-rate and flowing-pressure measurements, and laboratory pressure/volume/temperature (PVT) and fluid-analysis reports. The following diagnostic plots are used to identify potential errors or abnormalities in the production data: Rate/pressure/time plot (semilog) Productivity-index/time plot (semilog) Productivity-index/time plot (log-log) Rate/cumulative-production/time plot (log-log) Pressure/rate correlation plot (Cartesian) Rate/pressure/cumulative-production plot (semilog) In addition to checking the integrity and correlation of production data, the authors also use the following diagnostic plots to establish the reservoir model and flow regimes: Log-log plot Blasingame plot (log-log) Productivity-index/normalized-cumulative-gas-production plot (log-log) Note that, for the diagnostic plots, an incorrect estimate of the initial reservoir pressure will yield plots that show skewed trends or clumping or scattering of data points, particularly at early production times. On the basis of the information gathered from the diagnostic plots and well-history files, nonrepresentative production data points that are likely the result of nonreservoir effects or operational changes such as well-cleanup effects, liquid loading, well recompletions, well workovers, or choke changes are filtered. The diagnostic plots are prepared with the filtered production data to identify the flow regimes experienced by a given well. It is of primary importance to recognize if the well is still in transient flow or has already entered boundary- dominated flow because it allows determination of which of the time/rate relation models is appropriate for the given production data.

A visualization study of proppant transport in foam fracturing fluids

The placement of proppants in hydraulically fractured wells determines the conductivity of fractures and the productivity of shale wells. In slickwater farcturing, proppants are often not transported deep into fractures. In this paper, proppant transport in foam-based fracturing fluid is visualized in a laboratory-scale fracture slot. Effect of parameters like foam quality, proppant loading, and injection rate are systematically investigated. Experiments show that dry foams (80% quality) can carry proppants between the lamellas with little vertical settling. A complex flow pattern develops at the bottom of the slots in dry foams due to protrusion of foam fingers into proppant laden foam flow. Proppants are not carried very well in wet foams (70% quality) and form a proppant bed near the injection well. This is due to drainage of liquid and low effective viscosity of the foam as it moves through the fracture.

CAPITALIZATION OF RESOURCES OF NATURAL GAS OF SHALE FORMATIONS

Introduction. The article is devoted to problems of capitalization of natural gas resources of shale formations. Purpose. The article aims to develop methodological approaches to estimate the cost of natural gas resources of shale rock for their conversion through capitalization into assets, which can generate revenues and create added value. Results. The model for capitalization of shale gas resources in the subsoil has been developed. It allows to take into account the initial debits of shale wells, the rate of decline of deposits, the number of development cycles in the process of shale gas extraction, the accumulated shale gas extraction at different stages of development, the amount of investment and operating costs, time factor taking into account the natural and geological features and risks existing in the development of a specific shale deposit. The methodical approaches for determining the main parameters, which the proposed model includes, have been described.

Technology Focus: Water Management (December 2017)

Technology Focus Understanding and prioritizing water management is key for exploration-and-production operators, not only in terms of reducing overall cost and capital expenditures but also as a means of mitigating operational risk, complying with changing regulatory requirements, and addressing environmental concerns. Water-management decisions within shale oil and gas production fall into three primary categories: water acquisition, water usage within hydraulic-fracturing operations, and the disposal of produced and flowback waters from drilling and production. Shale-fracturing flowback refers to the portion of injected hydraulic-fracturing fluids that returns to the surface before and during initial production. The large quantities of flowback and formation water generated during the fracturing process must be treated before recycling, beneficial reuse, or disposal. Typically, 10–20% returns within 7–14 days, with a rapid decline in quality and quantity. Shale produced water typically refers to water produced during the production phase of the shale wells in the longer term and has significantly lower flow rates and more-consistent quality than flowback water. The characteristics of produced and flowback water vary, but both types of water must be treated properly and disposed of correctly or recycled. Numerous technologies are available today to enable complete or tailored removal of ionic, organic, and particulate contaminants from source waters for injection or produced waters for discharge. From fine-particle filtration to remove suspended solids and selective-ion exchange for boron removal to polymeric adsorbents for organic-compound removal, numerous water-management solutions are available to ensure that flowback water and produced water are treated properly for recycling, reuse, or disposal. The papers featured in this month deal with water management in south Argentina, a salt-tolerant friction reducer, and a novel water-shutoff system for carbonates. I hope you enjoy reading the selected papers. Recommended additional reading at OnePetro: www.onepetro.org. IPTC 18936 Integrated-Water-Management Challenges by H. Al-Shammari, Kuwait Oil Company, et al. SPE 183340 Innovative Approach To Treat Produced Water for Reuse in Saudi Aramco Reservoirs Pressure Maintenance by Mohamed Ahmed Soliman, Saudi Aramco, et al. SPE 183743 Maintaining Injectivity of Disposal Wells: From Water Quality to Formation Permeability by Ali A. Al-Taq, Saudi Aramco, et al. SPE 184520 On-Demand Water Control: Molecular Host/Guest Interaction for In-Situ Modification of Formation-Fluid Permeability by Antonio Recio III, Halliburton, et al.

Water-Management Experience in a Mature Basin in South Argentina

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 184931, “Water-Management Experience in Mature Basin in South Argentina,” by Clemente Marcelo Hirschfeldt, SPE, and Fernando Diego Bertomeu, SPE, Oil Production Consulting, prepared for the 2017 SPE Latin America and Caribbean Mature Fields Symposium, Salvador, Bahia, Brazil, 15–16 March. The paper has not been peer reviewed. Understanding and prioritizing water management is key for exploration-and-production operators, not only in terms of reducing overall cost and capital expenditures but also as a means of mitigating operational risk, complying with changing regulatory requirements, and addressing environmental concerns. Water-management decisions within shale oil and gas production fall into three primary categories: water acquisition, water usage within hydraulic-fracturing operations, and the disposal of produced and flowback waters from drilling and production. Shale-fracturing flowback refers to the portion of injected hydraulic-fracturing fluids that returns to the surface before and during initial production. The large quantities of flowback and formation water generated during the fracturing process must be treated before recycling, beneficial reuse, or disposal. Typically, 10–20% returns within 7–14 days, with a rapid decline in quality and quantity. Shale produced water typically refers to water produced during the production phase of the shale wells in the longer term and has significantly lower flow rates and more-consistent quality than flowback water. The characteristics of produced and flowback water vary, but both types of water must be treated properly and disposed of correctly or recycled. Numerous technologies are available today to enable complete or tailored removal of ionic, organic, and particulate contaminants from source waters for injection or produced waters for discharge. From fine-particle filtration to remove suspended solids and selective-ion exchange for boron removal to polymeric adsorbents for organic-compound removal, numerous water-management solutions are available to ensure that flowback water and produced water are treated properly for recycling, reuse, or disposal. The papers featured in this month deal with water management in south Argentina, a salt-tolerant friction reducer, and a novel water-shutoff system for carbonates. I hope you enjoy reading the selected papers. Recommended additional reading at OnePetro: www.onepetro.org. IPTC 18936 Integrated-Water-Management Challenges by H. Al-Shammari, Kuwait Oil Company, et al. SPE 183340 Innovative Approach To Treat Produced Water for Reuse in Saudi Aramco Reservoirs Pressure Maintenance by Mohamed Ahmed Soliman, Saudi Aramco, et al. SPE 183743 Maintaining Injectivity of Disposal Wells: From Water Quality to Formation Permeability by Ali A. Al-Taq, Saudi Aramco, et al. SPE 184520 On-Demand Water Control: Molecular Host/Guest Interaction for In-Situ Modification of Formation-Fluid Permeability by Antonio Recio III, Halliburton, et al.

Benchmarking EUR estimates for hydraulically fractured wells with and without fracture hits using various DCA methods

Various decline curve analysis (DCA) methods can be applied to forecast the production performance of hydrocarbon wells, including horizontal wells stimulated with hydraulic fracturing. Yet, which method is more preferable remains in doubt. The objective of this study is to evaluate various DCA methods by history matching and hindcasting both synthetic and field production data in order to assess for each method the reliability of production forecasts and the estimated ultimate recovery (EUR). Five DCA methods have been evaluated because of their computational simplicity and broad application. These methods are the Modified Hyperbolic Decline model (MHD), Duong model, Logistic Growth Analysis Model (LGM), and the Power Law Exponential (PLE, with D∞=0 and D∞=∞) Decline models. Each method was evaluated using three data sets: synthetic shale oil production rates based on a CMG reservoir model using Eagle Ford reservoir characteristics, data from producing Eagle Ford wells and from Austin Chalk wells. The hindcast method was applied to the Eagle Ford synthetic wells to establish the EUR deviation between the synthetic reservoir model production forecast and the various DCA methods. The weighted residuals of history matched production rates for Eagle Ford indicate that the MHD and Duong models give the lowest matching errors (as low as 1.32%) and the highest EUR estimations (as high as 3,447,609 stb). The PLE model (with D∞≠0) gives the most conservative EUR estimation, and also the least reliable history matching method (on our Eagle Ford data sets), which therefore is the least preferable DCA method. For the Austin Chalk wells in our study, all methods generate fairly similar EUR predictions with similar matching errors (from 13% to 15%) so that the DCA method preference becomes indifferent. This study also touches upon the relationship between DCA results when well interference occurs due to various hydraulic fracture hits. Shale wells that primarily contain hydraulic fractures and few natural fractures (Eagle Ford) give the most reliable forecasts using the MHD and Duong DCA methods. However, wells in the Austin Chalk, a naturally fractured reservoir, show little difference between the forecast accuracy from the various DCA methods.

Can the US shale revolution be duplicated in continental Europe? An economic analysis of European shale gas resources

Over the past decade, the rapid increase in shale gas and shale oil production in the United States has profoundly changed energy markets in North America, and has led to a significant decrease in American natural gas prices. The possible existence of large shale deposits in continental Europe, mainly in France, Denmark, the Netherlands and Germany, has fostered speculation on whether the U.S. shale revolution could be duplicated in Europe. However, a number of uncertainties, notably geological, technological, regulatory, and relating to public acceptance make this possibility unclear. We present a techno-economic model of shale gas production amenable to direct estimation on historical production data to analyze the main determinants of the profitability of shale wells and plays. We contribute an in-depth analysis of an extensive production dataset covering 40,000 wells and accounting for nearly 90% of shale gas production in the six main plays of the continental United States from 2004 to 2014. We combine this analysis with a discussion of the main differences between the American and European contexts to calibrate our model and conduct Monte-Carlo simulations. This enables us to estimate the distribution of breakeven prices for shale gas extraction in continental Europe. We find a median gross breakeven price before taxes and royalties of $10.1 per MMBtu. This would make extraction unprofitable in Europe in the current natural gas price environment, with <47% of the well distribution reaching breakeven at the mean 2011–2016 price. Sensitivity analysis reveals that the breakeven price is most sensitive to initial production rate, drilling and completion costs, and decline rates. We also find that the economic outlook would be slightly better if the productivity of European shale gas plays was comparable to that of U.S. plays of similar depth, but not significantly so. We conclude that under assumptions calibrated on existing shale gas production data, it is unlikely that the U.S. shale revolution can be duplicated in continental Europe.

Handling Uncertain Feedstock Compositions in Shale Gas Processing System Designs with Simulation-based Robust Equipment Capacities

The international gas market has been revolutionized by the advent of shale gas. As the shale gas production rate from a shale well declines over time, the mixture composition of raw shale gas gathered from multiple shale wells can be uncertain. This paper addresses the robust design and synthesis of shale gas processing and natural gas liquids (NGLs) recovery processes under uncertain feedstock compositions. The process feedstock comes from 8 shale wells with different raw shale gas compositions and the processed pipeline gas is to satisfy the fuel demand of a real world power plant. We employ monoethanolamine absorption, triethylene glycol absorption, and turboexpander-based NGLs recovery in the process designs to remove acid gases, water, and NGLs, respectively. Based on detailed process simulation and techno-economic analysis for each raw shale gas composition, we develop a robust process design with the minimum total direct cost of each operation unit needed to satisfy the pipeline gas demand. The robust process design can handle feedstock from the 8 shale wells with varying production flowrates. We perform a life cycle analysis for the robust design according to the Eco-indicator 99 methodology. The unit annualized cost is $1.8/GJ. Raw shale gas production and cooling utility generation are the major contributors to the environmental impacts of shale gas processing and NGLs recovery.

Shale EOR Works, But Will It Make a Difference?

When EOG Resources disclosed that it had found a way to get from 30 to 70% more oil from Eagle Ford shale wells, it set off a race among competitors looking for a low-cost way to add reserves by injecting natural gas. It has been little noticed because few companies have said anything publicly about it. But university researchers and service companies are seeing widespread interest from companies that are trying to figure out how EOG uses gas injection to increase production and whether those gains can be sustained long enough to add reserves. Research interest in gas injection enhanced oil recovery (EOR) persuaded David Schechter, a petroleum engineering professor at Texas A&amp;M University, to equip his lab that has been used to test carbon dioxide (CO2) for EOR to safely observe how natural gas affects reservoir rock. “Basically everyone with a substantial acreage position is working on unconventional oil EOR now,” said Schechter. “This is the name of the game. Everybody is talking about EOR and pumping money into trials of EOR,” said Deepak Devegowda, an associate engineering professor at the University of Oklahoma. The question facing EOG and its competitors is, can they take a method that improves results from some of its best wells, and use it on a far larger scale to increase overall recoveries in unconventional formations where more than 90% of the resource is left behind. Companies would like to understand and simulate it and, most importantly, they are looking for clues on how EOG did it. “A whole bunch of folks are watching what other people are doing,” Devegowda said. Companies and researchers are using statistical analysis to determine patterns in production data filed with the Texas Railroad Commission to try to figure out how EOG is using natural gas injection. Among those looking is Todd Hoffman, an associate professor from Montana State, who was initially skeptical of EOG’s claims. After studying the data, Hoffman said that EOG clearly is “seeing huge increases in added oil production.” He is now working on a paper based on the disclosures. As for how he figured out which of EOG’s more than 7,000 Eagle Ford wells to study, he said, “I really had to dig around to find it. I talked to a number of companies planning pilots, doing pilots, in the planning stage, trying to do the same thing,” he said.

Technology Focus: Artificial Lift (July 2017)

Technology Focus Two things stood out when I looked at this year’s abstracts. First, well over half of the abstracts were related to electrical submersible pumps (ESPs). This is a significant increase from the last couple of years. Second, there was a clutch of artificial-lift-method-selection papers. I have not seen many of those recently. Because this appears to be a topic of interest at the moment, I chose papers from that topic. They are good papers, and it is a good general-interest topic, but selecting them meant that I had to leave out more-specialized papers. I am primarily an ESP guy, so I have to be cautious about bias when looking at papers. Biased or not, I thought several of the ESP-related papers stood out. SPE 185128 discusses ways to operate an ESP below 800 psi. This has been a problem in multifractured horizontal wells. SPE 184216 discusses the effect of horizontal-well multiphase-flow behavior on ESP operations. Long gas/liquid slugs are another problem I have been seeing. SPE 172736 discusses casing corrosion induced by stray currents from weakened ESP-power-cable insulation. This is a topic of interest in the Middle East but is largely ignored in the US. I also admit to having a biased interest in multifractured horizontal shale wells. I thought SPE 180833 might be of interest because it discusses optimization of oil-well plunger lift. I have been wondering if plunger lift might be a viable late-life lift method for these wells. Last, SPE 180470 seemed like a solid gas lift optimization paper. As much as it pains me to admit it, by the book, gas lift should be the default lift method for shale wells. Recommended additional reading at OnePetro: www.onepetro.org. SPE 184134 Feasibility Study of Artificial-Lift Modes for a Deep Heavy-Oil Reservoir by Prasanna Mali, KOC, et al. SPE 185128 Breaking the 800-psi ESP PIP Barrier: How a Proven Flow-Conditioning Technology Can Dramatically Improve ESP Performance in Horizontal Wells by D.W. Kimery, Production Plus Energy Services, et al. SPE 184216 How To Diagnose and Solve a Tripping ESP Caused by Multiphase- Flow Behavior in a Horizontal Well by P.M. Bruijnen, TAQA Energy, et al.

Slug-Smoothing Technology Sees Over 200 Shale Installs, Gets Boost From Schlumberger JV

The undulating trajectories common to horizontal wells are the source of one of their greatest pain points—gas slugs. When these fast-moving accumulations reach the internals of an artificial lift system, a best case result may be a momentary pause in production. On the other hand, a gas slug could represent the bitter end for a lift system that may have cost six figures. The problem has been serious enough to drive operators in the Permian Basin to adopt an artificial lift strategy not historically used there. Manufacturers have responded to the challenge by trying to make pumps more slug-tolerant, while others are marketing automatic shut-down systems for asset protection. HEAL Systems has taken a different tact with a technology that it says removes slugging from the production equation by separating the horizontal from the vertical well sections and regulating the flow between them. The emerging innovation is called a horizontal-enhanced artificial lift (HEAL) system. It has no moving parts, and can be connected to any variant of lift system. In May, the company gained commercial steam through a joint venture with Schlumberger. Partnering with the service company will give HEAL Systems (formerly known as Production Plus Energy Services) manufacturing support and elevate its visibility in key markets such as the Middle East. “We’ve recognized that as a small company, scaling up is a challenge,” said Jeff Saponja, the chief executive officer of HEAL Systems, adding that the goal of the joint venture “is to get this technology out there, grow the company faster, and have access to an incredible research capability to develop it to the fullest.” Production Plus shareholders retain the majority share of the joint venture, allowing it to continue to market HEAL units to other service outfits and pump manufacturers. Based on its more than 200 installations in the US and Canada, the company is touting data that show its product has extended the run life of pumps in shale wells by months and sometimes years. Highlighted case studies of multiple wells in different formations claim this longevity has generated production improvements of 40–100% above prior baselines.