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Shammam, F. O. (Missouri University of Science and Technology) | Alkinani, H. H. (Missouri University of Science and Technology) | Al-Hameedi, A. T. (Missouri University of Science and Technology) | Dunn-Norman, S. (Missouri University of Science and Technology)
ABSTRACT: Refracturing old wells instead of drilling and stimulating new wells has become a new trend in the United States due to the oil prices falling in 2011. This work aims to disclose all refracturing activities in the most active shale play in the United States (Bakken, Niobrara, Marcellus, Permian, Eagle Ford, Barnett, and Haynesville) in terms of techniques, candidate selection, fracturing fluid types, and the number of refracs in one well. FracFocus was used to collect data of over 130,000 wells in the United States that were completed between 2013 to the end of 2019. The refractured wells were extracted from the database and the fracturing fluid types were classified as slickwater, linear gel, cross-linked gel, hybrid, and not reported treatments based on the presence of key chemical ingredients. After processing the data, there were over 1200 wells refractured across the most active shale plays in the United States. The results showed the most common fluid type used in refractured wells is hybrid. In terms of shale plays, Niobrara was the most active shale play with over 280 refractured wells followed by Bakken, Eagle Ford, Marcellus, Permian, Barnett, and Haynesville, respectively. Furthermore, the refracturing activities in each well were further analyzed and clustered into two groups; one or two refracs since some wells were refractured more than one time. However, over 95% of the wells were only refractured once. Moreover, refrac candidates can be identified based on the following factors; the original wells' cluster spacing, well spacing, proppant distribution, fracture orientation, production response from initial fracture, reservoir thickness, and permeability. The optimal ranges of the aforementioned parameters were provided to achieve the best results in terms of saving money and providing the best productivity. This will help optimizing future refracturing operations in the United States and all across the world.
Abstract Operators and investors are interested in finding better metrics to evaluate the production performance of unconventional multi-fractured horizontal wells (MFHWs). This paper discusses the use of cumulative productionratio curves,normalized to a given reference volume in time (e.g. 12-month cumulative production) for different unconventional plays in North America to investigate the median trend for each play, and investigate the median ultimate recovery per play. The selection of using 12-month cumulative production as a reference volume as a normalization parameter is discussed. Historical production data from thousands of MFHWs in unconventional plays in the US (Bakken, Barnett, Eagleford, Fayeteville, Haynesville, Marcellus and Permian) and Canada (Duvernay, Montney and Horn River) was used to calculate normalized cumulative production curves for theprimary fluid, using different cumulative reference volumes at different points in time (e.g. 6, 12, 24, 36, 48 and 60 months). The observed trends for each of the selected plays werestudied using data analytics tools. A two-segment hyperbolic decline was used to match the median production trend to estimate the long-term performance of each play. Depending on the data variance, some plays exhibit more clear trends than others. By using normalized cumulative production curves, general profiles for each play were generated and compared. These Cumulative Production Ratio Profiles (CPRP) were extended using a two-segment hyperbolic equation to determine the Expected Ultimate Recovery Ratios (EURR) per play. Once a well in a region has been on production for a minimum duration equal to the reference time (e.g. 12 months), two results are readily determined: a) the EUR, and b) the production profile. The EUR is obtained simply by multiplying the appropriate EURR by the well's 12-month cumulative production; and the production profile is obtained by using the CPRP (cumulative production ratio profile) of the play and multiplying it by the 12-month cumulative production of the welland converting the results to daily rates. This cumulative plot serves as a normalized typewell for the region and can be used to guide the production forecasts of wells with a short production life.
Abstract The story of the US shale revolution is well known. Hydraulic fracturing techniques were executed by Mitchell Energy in vertical Barnett Play gas wells in the early 2000's, vertical wells matured into horizontal multi-stage frac wells, and one of the largest land leasing campaigns in history exploded as operators chased high gas prices. As the natural gas market became saturated, the industry started to strip the natural gas liquids (NGLs) out of the gas stream to take advantage of the ever-rising oil pricing. When gas prices tumbled in 2011, and oil prices climbed north of $100/bbl, the industry looked to the liquid rich/oil plays, such as the Williston Basin, the DJ Basin, and the Permian Basin. The turning point came in November 2014 when oil prices fell rapidly. As prices bottomed out at $22/bbl in February 2015, the industry saw a large exodus of operators and capital from the gas rich plays around the US to the liquid rich Permian. The Permian proved to be the haven for oil and gas development with its multiple pay zone targets, high EURs, low break-even costs, friendly regulatory environment, and access to markets. The rush for land, once again ensued, with the hope of an oil price rebound and promise of high returns to capital investors. The rapid ramp up in activity from 2015–2018 did not come without challenges as it put strain on the availability of services and people, access to pipelines and markets, and access to frac sand/water. This drove up costs and resulted in mixed results for many companies. In addition, operators soon saw that with higher-than-expected gas and water production, expenses to manage these by-products sky-rocketed. Water handling and disposal became a huge portion of operating expenses and with gas export facilities at full capacity, companies started to flare gas in large volumes. Associated gas became a waste product, causing operators needed remove the gas and associated liquids from the revenue stream, and in some cases pay a high cost for flaring permits, rather than shutting in wells. By 2019, a shift in the investment community was well underway. The days of growth-focused investment were coming to an end, and investors wanted to see returns on their investments. As prices still hovered around the $55/bbl range, investors were getting anxious to recover their capital invested in the industry, and throughout 2019 operators all talked about the ability to generate free cash flow. This paper analyses the free cash flow for three key unconventional basins across the US and discusses the associated economic impacts in each basin.
Operators and investors are interested in finding better metrics to evaluate the production performance of unconventional multifractured horizontal wells (MFHWs). The complete paper discusses the use of cumulative production ratio curves normalized to a given reference volume in time for different unconventional plays in North America to investigate the median trend for each play and the median ultimate recovery per play. Many methods exist for forecasting the production rate from unconventional reservoirs, but all have limitations. Recently, several publications have appeared relating the expected ultimate recovery (EUR) to the initial rate or the cumulative production after 3, 6, or 24 months. In the complete paper, these publications are reviewed, and their learnings extended, to several unconventional reservoirs.
Abstract Petroleum produced from low permeability shales is different to the dispersed in-situ fluids from which it is derived. Whereas in-situ fluids consist of hydrocarbons, resins and asphaltenes in proportions governed by organic matter type, maturity and retention behaviour, the produced fluids are highly enriched in hydrocarbons and low polarity non-hydrocarbons, and show an enhanced GOR. Here, we study the effects of fractionation during production from Permian and Cretaceous shales using laboratory experiments, PVT-modeling and a regional PVT database. Our goal was to develop methodologies for predicting yields and compositions of produced fluids ahead of drilling. Target wells with known fluid properties were used for calibration. Shales from neighbouring wells of slightly lower maturity were mildly matured to that of the calibration well using MSSV pyrolysis, and a PhaseSnapShot of the resultant fluid made using PVTsim. The first example, from the late oil window Eagle Ford, demonstrates that both kerogen and bitumen are important petroleum precursors, and that in-situ compositions are largely determined by the most recently generated charge, rather than by cumulative addition during maturation. The PVT model, calibrated to the engineering report of the target well and its environs, reveals that a high proportion of the in-place C7+ fluids remain in the rock matrix relative to gas during production. The second example, taken from a gas and condensate fairway in the Permian Basin, shows that the predicted bulk composition of recently generated petroleum is facies dependent. PVT fluid calibrations have low Psat and low cricondentherms. These characteristics are reproduced by experiment, but only for those zones containing low contents of high molecular weight liquids. Any contributions to produced fluids from other zones is associated with massive retention of high molecular weight organics. The third example concerns volatile oil production from wells in the Permian Basin. The MSSV products generated by adjacent lower maturity shales exhibited phase envelopes with higher cricondentherms than that of the calibration, this being attributable to a molecular weight difference in heavy components. Adjusting the MW from 249 (measured) to 222 (produced oil PVT value) in the PVTsim model aligned the cricondentherms. This tuning step corresponds to the preferential retention of heavy polar compounds in the rock matrix during production. In a second step, 20% of the tuned MSSV-generated liquids are considered to be retained in the rock, thereby raising Psat. The result is an excellent match between the doubly tuned predicted phase envelope and that of the produced fluid. The preferential retention of polar compounds is also in line with this tuning step. In summary, fractionation is part and parcel of production from shales. Up to 80% liquids retention relative to gas has been demonstrated. Production efficiency assessments are readily inferred from these data. The extent to which fractionation occurs varies a lot, and has here been assessed by combining experimental rock geochemistry with PVT modeling (PhaseSnapShots), and using PVT reports on produced fluids for calibration.
Rosenhagen, Nicolas M. (Colorado School of Mines) | Nash, Steven D. (Anadarko Petroleum Corporation) | Dobbs, Walter C. (Anadarko Petroleum Corporation) | Tanner, Kevin V. (Anadarko Petroleum Corporation)
Abstract The volume of stimulation fluid injected during hydraulic fracturing is a key performance driver in the horizontal development of the Niobrara formation in the Denver-Julesburg (DJ) Basin, Colorado. Oil production per well generally increases with stimulation fluid volume. Often, operators normalize both production and fluid volume based on stimulated lateral length and investigate relationships using "per-ft" variables. However, data from well-based approaches commonly display such wide distributions that no useful relationships can be inferred. To improve data correlations, multivariate analysis normalizes for parameters such as thermal maturity, depth, depletion, proppant intensity, drawdown, geology and completion design. Although advancements in computing power have decreased cycle times for multivariate analysis, preparing a clean dataset for thousands of wells remains challenging. A proposed analytical method using publicly available data allows interpreters to see through the noise and find informative correlations. Using a data set of over 5000 wells, we aggregate cumulative oil production and stimulation fluid volumes to a per-section basis then normalize by hydrocarbon pore volume (HCPV) per section. Dimensionless section-level Cumulative Oil versus Stimulation Fluid Plots ("Normalization" or "N-Plot") present data distributions sufficiently well-defined to provide an interpretation and design basis of well spacing and stimulation fluid volumes for multi-well development. When coupled with geologic characterization, the trends guide further refinement of development optimization and well performance predictions. Two example applications using the N-Plot are introduced. The first involves construction of predictive production models and associated evaluation of alternative development scenarios with different combinations of well spacing and completion fluid intensity. The second involves "just-in-time" modification of fluid intensity for drilled but uncompleted wells (DUC's) to optimize cost-forward project economics in an evolving commodity price environment.
Oraki Kohshour, Iman (University of Wyoming) | Leshchyshyn, Tim (FracKnowledge/Fracturing Horizontal Well Completions Inc.) | Munro, Jason | Yorro, Meaghan Cassey (Forum Energy Technologies) | Adejumo, Adebola T (Halliburton) | Ahmed, Usman (Unconventional Oil and Gas Technology and Development and WellDog) | Barati, Reza (University of Kansas) | Kugler, Imre (IHS Markit) | Reynolds, Murray (Ferus) | Cullen, Mike (Ferus) | McAndrew, James (Air Liquide) | Wedel, Dave (Air Liquide)
Summary With increasingly stringent regulations governing the use of fresh water in hydraulic fracturing, operators are struggling to find alternative sources of fracture fluid for hydraulic fracturing operations. In some regions of the world where abundant fresh water is not available, such as the Middle East and China, using large amounts of fresh water for fracturing is not possible to develop fields. FracKnowledge Database tracking of USA water usage per well indicates that, on average, a well requires 3 to 6 million gallons of water, even up to 8 million for the entire life cycle of the well based on its suitability for re-fracturing. This depends on the number of fracturing stages and particular characteristics of the producing formation. The same industry sources also suggest that about 30 to 70% of injected water remains in the formation with unknown fate and potential consequences to formation damage. Sourcing, storage, transportation, treatment, and disposal of this large volume of water could account for up to 10% of overall drilling and completion costs. As a transition to a reliable and complete replacement for water in the fracturing fluid, mixtures of fresh water with produced and brackish water are being applied. On the other hand, waterless fracturing technology providers claim their technology can solve the concerns of water availability for shale development. These waterless or minimal water methods have been used for decades, but are higher cost than conventional water fracturing techniques and have usually been used in water sensitive formations that required the technology. This study reviews high-level issues and opportunities in this challenging and growing market and evaluates key drivers behind water management practices such as produced and flow-back water, waterless fracturing technologies and their applications in terms of technical justification, economy and environmental footprint, based on a given shale gas play in the United States and experience gained in Canada. Water management costs are analyzed under a variety of scenarios with and without the use of fresh water. The results are complemented by surveys from several oil and gas operators. With low economic margins associated with shale resource development, operators need to know which practices give them more advantages and whether waterless methods are capable of fracturing the wells at optimal conditions. Based on a high-level economic analysis of cost components across the water management value chain, we can observe relative differences among approaches. Our analysis does not consider the effect of fracture fluid on productivity, which can be considerable in practice. Bearing this limitation in mind, as one might expect, fresh water usage offers the greatest economic return. In regions where water sourcing is a challenge, however, the short-term economic advantage of using non-fresh water-based fracturing outweighs the capital costs required by waterless fracturing methods. Until waterless methods are cost competitive, recycled water usage with low treatment offers a similar NPV to that of sourcing freshwater via truck, for instance. Despite positive experiences with foamed fracturing techniques in Canada, and the potential improvements offered by these techniques, the technology is still challenging to apply in large scale fracturing jobs in the United States, primarily due to operators' perceived level of technology complications, safety, economics, and other logistics. However, if these emerging technologies become widely accepted, the development of shale resources, especially in those basins exposed to drought, has the potential to grow both nationally and internationally. Although environmentally friendlier than using fresh water, the environmental aspects of these technologies must be clarified and deserve closer examination. Such variables must be reviewed based on specific shale reservoir characterizations before implementation on a large scale, and there are numerous other supply logistics and HSSE-SR (Health, Safety, Security, Environment, and Social Responsibility) issues that need additional discussion. Conclusions regarding current and future shale development have been proposed based on results from comprehensive technical, environmental, economic, and regulatory evaluations.
Summary Understanding organic porosity and its structural development in source rock reservoirs is essential to understanding how it can influence flow properties. A field emission scanning electron microscope (FESEM) was used to study the structure of the organic matter (OM) in shale samples as maturity increases. Argon ion milling of shale samples has proven to be a very powerful tool in understanding pore systems in shale, however, artifacts from this technique have been shown to obscure the OM structure. Consequently, fresh cleavage samples were imaged in addition to the argon ion-milled samples. The presence of oil/bitumen creates a challenge to observe the OM pore system by SEM techniques. To overcome this problem eight shale samples, from six different geological formations with a maturity range from 0.66 to 1.82 %Ro equivalent were observed, before and after CO2-toluene cleaning. OM at low maturity levels (<0.7 %Ro equivalent, from T-max values) is composed of sub-spherical units, generally 7–12 nm in diameter. With increasing maturity, these spherical subunits are connected, creating a network of OM. The spaces between these particles and the spaces within the connected framework determine the OM pore sizes, shapes, and distribution. Observations made by SEM showed OM structural changes from spherical structures to a crosslinked network in the OM that may be associated with maturity. Introduction Porosity occurring within the OM of potentially oil producing shales is not as well understood as in gas producing shale plays. Understanding the OM structure in oil plays may help understand flow and porosity measurements and help resolve challenges in establishing a multiscale approach. Coring is defined as the downhole acquisition and recovery of reservoir formation material, so it is important to understand that all laboratory testing is conducted on samples in as received (AR) state which may not be in their unaltered in situ state prior to core retrieval, and it is likely that some changes have occurred during coring, sampling, and handling procedures (Handwerger et.al. 2012). Observing pore systems in oil producing plays is difficult as the pore spaces may be filled or partially filled by fluids (indigenous and/or coring fluids) which makes it difficult to distinguish OM structures by SEM techniques. For this reason, observation of shale samples needs to be performed on AR samples as well as after cleaning to better observe changes in the pore system. There are several laboratory techniques available to clean core samples and, in general, they all have positive and negative attributes. The selection of best solvents greatly depends on rock type, the ability to remove fluids, and must not react with the rock sample. The CO2-toluene (CO2-tol) core cleaner is a widely used apparatus to clean crude oil, water, and drilling mud liquids from whole core samples in preparation for porosity and permeability measurements and was used in this study for the after cleaning SEM observations. While the removal of pore filling material will increase porosity, shrinkage of the OM may also take place thus increasing porosity. In 2010 Loucks et.al. described a type of pores that appeared to be the result of OM shrinkage. SEM observation of CO2-tol cleaned samples helped to understand to what extent the OM had undergone shrinkage compared to the AR samples when using this method.
Abstract Most of the shale reservoirs in US land are naturally fractured. The fracture intensity and types vary from one shale to another. Even within the same shale in the same field, the heterogeneity of fracture intensity can be often expected to be high in a horizontal well. The current popular geometrical completion design can potentially ignore the existence of natural fractures. Hence, maximizing stimulation efficiency without understanding existing natural fractures can be a challenge. In this paper, study was made of the majority of the published case studies related to natural fractures in the US shales in the last 20 years. The evidence of natural fractures from either outcrops or subsurface data, i.e. core, borehole images, or other data is summarized for each studied shale. The latest studies show that the hydraulic fracture propagation can be strongly influenced by existing natural fractures regardless of whether they are open or closed. The roles of existing fractures in the shales include: 1) providing enhanced reservoir permeability for improved productivity if they are open and effectively connected by hydraulic fractures; 2) promoting much better fracturing network complexity regardless of whether they are open or closed prior to the stimulation; 3) giving possible negative impact sometimes, i.e. high water cut, if they are connected with wet zones below or above the reservoirs. It can be concluded that engineered completion designs that employ accurate knowledge of natural fracture data, in-situ stresses, and other reservoir and completion quality indicators as inputs can provide opportunities for enhancing stimulation efficiency and fracturing network complexity. This in turn can lead to better connectivity to a larger reservoir volume and access to more drainage area in the shales. Introduction The US shale gas story actually featured natural fractures. William Hart, a local gunsmith, drilled the first commercial natural shale gas well in US in Fredonia, Chautauqua County, NY in 1821, in shallow, low-pressure rock with fractures. The well was first dug to a depth of 27ft in a shale which outcropped in the area, then later drilled to a depth of 70ft using 1.5 inch diameter borehole. The produced gas was piped to an innkeeper on a stagecoach route. Then the well was produced without any stimulation for 37 years until 1858 when it supplied enough natural gas for a grist mill and for lighting in four shops. It was a combination of the idea from Mr. Hart to drill the well and the presence of the natural fractures in the gas shale that made the 1 commercial shale gas discovery possible in shale gas history.
Summary Calcite forms variable proportions of source-rock reservoirs ("shale plays"). Although calcite content can be quantified via petrophysical analyses, XRD, XRF and other techniques, the amount of calcite, by itself, is not enough information to predict the likely importance of these minerals for reservoir and completions quality. Four principle types of calcite can be recognized:Pelagic components, mostly foraminifera and coccoliths, form a large component of the Eagle Ford and Niobrara but other types of pelagic carbonates (e.g., tentaculitids) are common in Paleozoic source-rock plays such as the Marcellus, Carbonate "event beds" (turbidites, storm deposits, etc.) are present in the Avalon, Barnett, Vaca Muerta and other plays, In situ benthic carbonates (bivalves, corals) are present in some plays (e.g., Eagle Ford, Marcellus), and Diagenetic calcites (pore filling cements, fracture fills, replacements, etc.) are present to varying degrees in perhaps most source-rock plays. Detailed core descriptions and petrographic observations are critical for assessing the origin of the calcite. Similar concepts apply to other mineral and organic components of mudstones.