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Collaborating Authors
Delaware Basin
Three Years of Water Treatment in the Permian: A ConocoPhillips Case History
Shields, Austin (ConocoPhillips) | Sharma, Ramesh (ConocoPhillips) | McLin, Kristie (ConocoPhillips) | Bjornen, Kevin (ConocoPhillips) | Jenneman, Gary (ConocoPhillips) | Freeman, Jason (ConocoPhillips) | Mesa, Willie (ConocoPhillips)
Abstract In the Permian Basin, fresh water supplies are becoming increasingly scarce. Competition for fresh water and expensive trucking costs have driven up total well costs and placed strains on the supply of water for hydraulic fracturing. However, ample supply of produced water makes it a prime candidate for treatment and reuse. Initial water treatment efforts focused on vertical well completion candidates. Before field implementation, bench scale testing was conducted to evaluate the viability of H2S oxidation and subsequent filtration as a produced water treatment method. The water team achieved satisfactory friction reduction and gel stability from sour water treated with oxidizer. Water-reservoir compatibility was also evaluated before pumping the first job. The completion team developed a simple, effective method of diverting produced water from the battery, then treating, storing, and transferring the treated water to location. Five wells were completed in the initial run, with two wells using a fresh water/treated produced mixture and three wells using 100% treated produced water. A thirteen well follow-up vertical program was later completed using 100% treated battery water. With the concept proven for H2S removal and completion in vertical wells, the next step was to apply previous learnings to fracture horizontal wells in the Delaware basin. Produced water in the Delaware contains over 200,000 ppm total dissolved solids (TDS) and has significant iron concentration (>100 ppm), making it a challenging candidate for treatment. The authors successfully executed oxidation treatments for the removal of iron and completed a four well horizontal program with up to 50% treated produced water used per well. Based on the success of this project, the authors are planning full field implementation of produced water reuse as a water management strategy for the Delaware basin assets. Reusing produced water has important environmental benefits, reducing the amount of fresh water needed during hydraulic fracturing and minimizing truck traffic, both of which are outcomes consistent with sustainable development goals. This work fulfills a commitment in our company's Water Sustainability Action Plan and will play a vital role in future development.
- North America > United States > Texas (1.00)
- North America > United States > New Mexico (0.78)
- Water & Waste Management > Water Management > Lifecycle > Treatment (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (23 more...)
Abstract The Midland Basin Wolfcamp formation of upper Pennsylvanian through lower Leonardian age, has experienced a substantial increase in both vertical and horizontal activity in the past five years. The Wolfcamp formation is regionally extensive within the Midland basin and is composed of four subunits; Wolfcamp A, B, C and D (lower Wolfcamp through upper Wolfcamp). Multiple interfingering depositional environments are observed causing for complex, high-frequency lithologic variation within individual stratigraphic sections. These varying forms of sediment distribution are directly linked with proximity to the major carbonate production centers in the region, the Central Basin Platform and the Eastern Shelf. Litho-facies can range from mega-breccia proximal to the central basin platform to sediment gravity flows that reach out into the axis of the basin. Variable physical mechanisms of sediment dispersal due to differing environments of deposition lead to fundamentally unique sets of complexly stacked lithofacies. It is this heterogeneity that makes the identification of horizontal landing zones difficult based solely on conventional wireline logging methods. High-resolution XRF chemostratigraphic methods are herein documented to improve landing zones for horizontal wells. In order to account for this lithologic heterogeneity, X-Ray Fluorescence (XRF) chemostratigraphy was employed to help identify potential landing zones through major and trace element analyses. Redox sensitive trace metal abundances of Mo, Ni, U, V, Se, and Cu can be used to infer intervals of increased preservation potential within the core using high resolution (2-inch) spacing on core analysis. Not only can the trace elements shed light into the levels of oxygenation at the sediment/water interface, but can also provide insight into the mineralogical variations along the horizontal well bore providing additional data to contribute to more accurate engineered fracturing designs. These measurements along the lateral are conducted on cuttings and run through a bench top XRF onsite for rapid understanding of changing conditions. Identifying favorable landing zones has been demonstrated to increase EURs in multiple wells, and future work will focus on deploying XRF based chemostratigraphy to further refine landing zones throughout the Midland basin, and lower overall well costs.
- Geology > Geological Subdiscipline > Stratigraphy > Chemostratigraphy (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.55)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (37 more...)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Summary Samples from two shale successions from two boreholes drilled in the Lower Permian strata of the Delaware Basin were investigated and assessed in terms of palaeoredox conditions during the sediment deposition, basin hydrography, and the application of the elemental data for the organic carbon content prediction. The strata, composed of the alternating calcareous shale/limestone and siliciclastic shale intervals showed to have only minor biogenic silica input, with the major biogenic component being of the carbonate source, and the siliciclastic fraction dominated by the terrigenous material. The authigenic enrichment in elements typical for anoxia and elevated palaeoproductivity (Ni, Cr, V, Cu, Mo, U) was revealed to be inconsistent throughout the shale sequence, with the major change in the trace element - Total Organic Carbon (TOC) correlation trends at TOC ca. 2%. For organic- lean rocks, low concentrations in all the redox elements, and their high normalized values as compared to reference shales, suggest deposition in anoxic/euxinic waters, but with the redox signature masked by the strong carbonate dilution. In the organic-rich rocks, multi-element covariations show patterns typical for anoxia, with elemental concentrations not affected by the slow background terrigenous sedimentation. The limited enrichment in Mo and U in the most organic-rich shales (up to 7% TOC) suggest that the hydrographic conditions had a critical effect on the limited deposition of the most conservative trace elements during the terrigenous sedimentation intervals. In such scenario, Nickel (Ni) proved to be a valuable proxy for the organic carbon deposition, with a sufficient predictive power to predict TOC in unknown shale successions. The evaluation of the Lower Permian Shale successions showed how critical the geochemical approach is when assessing shale sequences in relatively unknown basins, and their potential to store hydrocarbons.
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Mungaroo Formation (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Carnarvon Basin > Dampier Basin > Rankin Platform > Greater Gorgon Development Area > Block WA-268-P > Greater Gorgon Field > Gorgon Field (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Carnarvon Basin > Carnarvon Basin > Rankin Platform > Greater Gorgon Development Area > Block WA-268-P > Greater Gorgon Field > Gorgon Field (0.99)
- (38 more...)
Integrating 3D Seismic and Geomechanical Properties with Microseismic Acquisition and Fracturing Parameters to Optimize Completion Practices within the Wolfcamp Shale Play of the Midland Basin
Shoemaker, Michael (Callon Petroleum Company) | Zakhour, Nancy (Schlumberger) | Peacock, Joshua (Callon Petroleum Company)
This study presents a successful empirical approach based on the integration of numerous multidisciplinary measurements to optimize completion methodologies and future field development strategies for stacked lateral wellbores, and essentially to high-grade exploratory Wolfcamp landing zones from 3D seismic data. Specifically, we measured mineralogical and geomechanical shale properties directly from 3D surface seismic data lengthwise along lateral well trajectories at individual frac stages which were monitored real-time using microseismic acquisition. Linear regression analyses for calibration show strong correlations between inverted seismic P-wave impedance versus microseismic data and fracture pressure responses, shale mineralogy compositions, and geomechanical properties calculated from core data. The method was recently tested in the prolific oil-bearing Wolfcamp shale-oil play of the Midland Basin, West Texas, on three horizontal laterals drilled in a "chevron pattern", two of which in the deeper Wolfcamp B formation and the third in the Wolfcamp A. Real-time microseismic monitoring was used to observe the hydraulic fracturing treatments and the resulting heights and lateral extent. Although identical pumping schedules were initially intended for all three laterals stimulated in a "zipper sequence", with geometric stage placement, it became apparent during the treatments that microseismic height growth varied significantly across the given laterals within individual stages. The results of our combined analysis showed that microseismic fracture height variability is most influenced by changes in shale stratigraphy and subsequent mineralogy composition, without a definitive relationship with treatment injection rates. Optimal fracture heights were observed in landing areas with significant volume of calcite, characteristic of high Young's modulus and closure stress, variables which in turn were estimated from 3D seismic. For validation, production history of said laterals and numerous others in the field confirms a strong correlation between seismic P-wave impedance and initial 120 day cumulative oil in landing zones where high volume of calcite and hence brittleness exists. 2 SPE-178575-MS/URTeC:2154184
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.95)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (0.70)
Evolving Petrophysics of the Overburden: A Spectroscopy Approach
Chatterjee, Amitabha (Schlumberger) | Datir, Harish (Schlumberger) | Baig, Mirza Hassan (Schlumberger) | Horkowitz, Jack (Schlumberger) | Grau, Jim (Schlumberger) | Goonting, Jeremy (ConocoPhillips) | Haneferd, Helen (ConocoPhillips) | Tompkins, Dianne (ConocoPhillips) | Wendt, Brett (ConocoPhillips)
Abstract The Greater Ekofisk area produces from naturally fractured chalk reservoirs in the North Sea. While knowledge of the reservoir itself is essential, it is equally important to have a thorough characterization of the overburden that lies above. Continuous measurements with high vertical resolution are required to address numerous challenges for drilling, completions, sustainable production, and abandonment operations narrow drilling windows, wellbore stability, compaction, subsidence, fault reactivation, and fluid containment-that increase costs and reduce well life. Previously integrated core studies, acoustic measurements, seismic surveys, and well logs document complex mineralogy: mixed clays, quartz, feldspars, carbonates, and iron-rich heavy minerals. In addition, these highly porous overburden shales contain a variable amount of organic matter and naturally occurring free-gas volumes. Pressure seals, swelling clays, fracture potential and orientation, and rock strength have mineralogical sensitivity below seismic resolution. In prior work in the field, building a proper geologic and geomechanical model at the appropriate scale was attempted with well logs, but the available capture-only spectroscopy data could not provide the richness required for solving the high number of unknowns present in the non-reservoir overburden rocks. The lack of estimated organic matter volumes combined with the uncertainty in clay types and volumes in an iron-rich environment in the presence of free gas challenged the petrophysical models. Recently, a reevaluation was attempted using a new high-definition spectroscopy tool, guided by the prior knowledge of the overburden rocks. Measurement of both capture and inelastic spectra provided greater confidence in the clay analysis from direct aluminum measurements. Also solved were the previously unresolved organic matter through carbon measurement, dolomite through magnesium measurement, and rhodochrosite through manganese measurement. These new measurements have led to a significantly increased confidence in the petrophysical model, allowing it to evolve further.
- North America > United States (1.00)
- Asia > Middle East (0.93)
- Europe > Norway > North Sea > Central North Sea (0.48)
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.48)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.48)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (45 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
Formation Evaluation of Multiple Pay Zones Within an Unconventional Reservoir (Permian Basin): An Integrated Interpretation using Elemental, Mineralogical, Programmed Pyrolysis, and Mud Gas Data.
Mainali, Pukar (Weatherford Laboratories) | Yemidale, Gbenga (Weatherford) | Hankins, Brian (Weatherford Laboratories) | Matson, Christopher C. (Weatherford Laboratories)
Abstract A 3,680 foot (1122 m) vertical Permian Basin well was evaluated using an integrated, multi-instrument dataset acquired while drilling to identify zones of interest for lateral targets. A total of 161 cuttings samples were analyzed to determine the mineralogical (X-Ray Diffraction; XRD), organic (programmed pyrolysis via Source Rock Analyzer), and elemental (Energy Dispersive X-Ray Fluorescence spectroscopy; ED-XRF) composition while gas in air and gas in mud samples were analyzed every foot using a quadrapole mass spectrometer and a Thermal Conductivity Detector (TCD; GC-TRACER™) respectively. Each zone identified as a potential reservoir target exhibits TOC values above 2 wt%, Total Gas (THC %) 3 to 5 times greater than the background gas, Tmax and methane content (C1%) or C1/THC values suggesting that the reservoir has reached thermal maturity for mixed type II/III kerogen type determined from Hydrogen and Oxygen Index ratios, and S1 values above 1 mg/g considered adequate for unconventional reservoir production. The zones are further evaluated based on their mechanical properties including bulk mineralogy, calculated Brittleness Index, fluid properties, C1/ROP, and Helium concentration then ranked based on the likelihood of brittle behavior and fractures present during reservoir stimulation. Additionally, conditions most favorable for extensive organic matter preservation during the time of deposition were assessed using elemental proxies such as V, Ni, Mo, and U and were evaluated to further rank each zone by statistical correlation to organic and gas values (regression; R). Of the three zones of interest identified, Zone C spanning 650 feet of the lower Pippin, lower Wolfcamp, Cisco and Cline and specifically one narrow target Organic Zone 8 within Zone C was determined to exhibit the best mechanical, geochemical, gas saturation, and elemental characteristics among all lateral targets in the wellbore. This technique of combining sophisticated cuttings analysis with advanced gas-in-mud detection systems deployed at wellsite allowed the operator to make more informed drilling decisions by not only identifying zones of interest but also the ability to rank each zone based on the most favorable mineralogy, mechanical properties, hydrocarbon content and quality, fluid type and maturity, relative permeability, relative water saturation, and paleoredox and organic matter proxies most associated with greatest potential. Additionally, these technologies and techniques can also be employed to determine wellbore position during the build and also characterize the reservoir in the horizontal to better inform completions decisions.
- North America > United States > Texas (1.00)
- North America > United States > New Mexico (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.98)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.47)
- Government > Regional Government > North America Government > United States Government (0.46)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- (61 more...)
- Well Drilling > Drilling Measurement, Data Acquisition and Automation > Mud logging / surface measurements (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Geochemical characterization (1.00)
Abstract McElroy Field, located in the Permian Basin, is a typical example of a complex carbonate reservoir. Discovered in 1926, McElroy Field has been under waterflood since the early 1960's. However, maximizing oil recovery is still a major challenge in this field. A comprehensive analysis on the distribution of depositional facies and diagenetic modifications can ultimately enhance future development and oil production in the McElroy Field. We have applied a rock typing workflow based on conventional well logs and core data to incorporate both depositional and diagenetic attributes for characterizing the heterogeneity within the McElroy Field. The applied rock typing workflow consists of several sequential steps. Firstly, the depositional rock types were described and consolidated in the core domain for the purpose of propagation into the well-log domain. Reservoir typing was then conducted to identify controls on reservoir properties. This analysis indicated that diagenetic overprint has the dominant influence on the fluid flow in the McElroy Field. Pore type groups were classified by clustering attributes of Gaussian function fits to the pore-throat radius distributions derived from Mercury Injection Capillary Pressure (MICP) measurements. The identified depositional rock types and pore type groups were populated in the core-plug and the well-log domains applying a supervised model trained using k-Nearest Neighbors algorithm (KNN). Vuggy porosity was characterized in the core domain using CT-scan imaging techniques and correlated to log-derived estimates of porosity to predict vuggy porosity in the well-log domain. Assessment of vuggy porosity using CT-scan image analysis showed that the separation of sonic porosity and density-neutron porosity is not a reliable tool for estimating vuggy porosity in gypsum-bearing reservoirs. All of the generated geological and petrophysical data were integrated to define the petrophysical rock types that control the reservoir's dynamic characteristics. Identified petrophysical rock types were validated using dynamic injection profiles. The obtained results showed that the fluid flow in this field is dominantly controlled by diagenetic modifications. Finally, we studied the distribution of the identified petrophysical rock types to establish trends for field-wide spatial distribution of petrophysical rock types. The spatial trends of petrophysical rock types in the field serve to unveil the potential for future development opportunities in the McElroy Field.
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.46)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Strong Field (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- (31 more...)
The Case for Making Conventional Petrophysical Workflows in HAHZ Wells Obsolete
Stockhausen, Ed (Chevron) | Rasmus, John (Schlumberger) | Xie, Hui (Schlumberger) | Morriss, Chris (Schlumberger) | Ito, Koji (Schlumberger) | Griffiths, Roger (Schlumberger) | Maggs, David (Schlumberger) | Abubakar, Aria (Schlumberger)
Abstract Conventional petrophysical workflows that make use of point-by-point inversions of measured log data to determine reservoir properties at every sampled measure point may now be rendered obsolete. These workflows and inversions assume the tool is surrounded by an infinite homogeneous medium and the tool sensors are unperturbed by adjacent layers. This assumption is approximately correct when vertical wells are drilled through thick massive reservoirs. In this case, 1D inversions are available for the deeper-reading induction measurements to provide approximate corrections at layer boundary crossings. However, these inversions are for a single tool, and the position of each boundary is placed to satisfy that tool's responses without regard to the actual geological boundary position. Additionally, these inversions do not incorporate any nuclear measurements, making the computation of saturation using a 1D squared log of resistivity with a simple measured nuclear log impractical. Reservoirs today are being developed using high-angle and horizontal (HAHZ) wells using a single platform or pad for multiple wells. This reality, and the fact that thin-bedded formations such as organic shale reservoirs are now being exploited, results in both resistivity and nuclear measurements that are affected by multiple layers at each measured depth, regardless of whether the conveyance is by logging-while-drilling (LWD) or wireline, and in measurements that are not characteristic of any one layer. Interpretation is further complicated by the fact that some measurements are directional and measure at some particular azimuth of the formation, e.g., wireline pad density measurements or best-contact LWD density measurements, and others, such as resistivity and neutron, are omnidirectional and respond to properties at all azimuths. A new workflow is developed to address the geometrical and tool response issues associated with HAHZ well measurements. First, we take advantage of the high "effective" resolution of the density measurement that is a result of the high relative bed dip to define petrophysical layers as thin as 2-in. true stratigraphic thickness (TST) space. Next, the true-layer log properties are determined from inversion and forward modeling. This allows us to compute the layer petrophysical properties of porosity, saturation, fluid type, and permeability using conventional petrophysical algorithms. Another unique aspect of the workflow is that properties are also determined for the non-crossed layers—those that are proximal to and within the volume of investigation of the measurement, but not actually crossed by the well trajectory, i.e., for parallel bed conditions. The reservoir hydrocarbon pore volumes and permeability can now be computed on a layer-by-layer basis free of adjacent bed and bed-crossing effects. The integration of these petrophysical layer properties can now be used as input to reservoir property modeling and upscaling exercises. In a particular field case, the new workflow computed layer boundaries and porosity and permeability match core properties in beds as thin as 3 in. whereas the previous vertical well derived properties do not. The use of the newly derived layer properties enables us to more accurately quantify porosity and permeability and explain the unexpected high hydrocarbon flow rates in some layers and the early water breakthrough from water injection in others. With this new information we can now place subsequent development wells in optimal positions to increase ultimate recovery.
- Europe (1.00)
- Asia (1.00)
- North America > United States > Texas > Travis County > Austin (0.28)
- Geology > Geological Subdiscipline > Stratigraphy (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.67)
- North America > United States > Texas > Permian Basin > Delaware Basin (0.99)
- North America > United States > New Mexico > Permian Basin > Delaware Basin (0.99)
- North America > United States > Kansas > State Field (0.99)
- Well Drilling > Well Planning > Trajectory design (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
Abstract Carbonate reservoirs are inherently complex in their nature. This complexity is due to a combination of depositional rock fabric textures and diagenetic modification of the rocks. Post-depositional processes can modify the original petrophysical properties (e.g. permeability, irreducible water saturation and relative permeability) and result in a disconnection between original depositional rock fabric and current reservoir properties. Pore types are a critical element of rock types since they exert a dominant control over petrophysical properties and fluid flow. Their proper definition is especially important in complex carbonates with multiple pore systems. Several papers, however, restrict pore typing to MICP groups without transferring to log domain necessary for reliable earth modeling. A procedure has been developed to describe the dominant pore types occurring within a carbonate reservoir based on the interpretation of standard core data, mercury injection capillary pressure data and wireline log data. This procedure incorporates the following components: sample selection methodology, data acquisition, data quality control and corrections, parameterization of the MICP curves using Gaussian decomposition, clustering, extrapolation of MICP derived pore types groups (PTGs) to all core plug samples, and lastly prediction in the log-domain. The workflow described here is unique in that it describes the process from sample selection through log-scale prediction, PTGs are defined independently of the original depositional geology, parameters which describe the whole MICP curve shape are utilized, and objective clustering is used to remove subjective decisions. In this paper, we will describe the proposed workflow and present a case study from a carbonate field where characterizing PTGs in this way provided a better understanding of controls on rock properties and fluid flow than was achieved by looking at the depositional facies alone.
- North America > United States > Texas (1.00)
- Asia (0.68)
- Geology > Rock Type > Sedimentary Rock (0.94)
- Geology > Geological Subdiscipline (0.88)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (31 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (0.89)
Abstract This work builds on Bonapace et al. (2015), specifically discussing shale reservoir information related to several tight reservoirs in Argentina. Hydraulic fracturing has been ongoing in Argentina since the 1960s. The first treatments were performed using oil-based fluids. Throughout the years, new water-based fluids were introduced, as well as alcohol-water mixture fluids to foams, based on the reservoir requirements, economics, and safety and environmental issues. Currently, more than 95% of hydraulic fractures performed in the country are performed using aqueous-based fluids. In the last 10 years, exploration and development has begun for tight gas reservoirs and more recently several shale plays. To achieve commercial production, this type of reservoir requires extensive hydraulic fracturing applications which use large volumes of water. From 2004 to present, various exploration techniques have been performed in different reservoirs, such as tight formations at Lajas, Punta Rosada, Mulichinco (Neuquén Basin); Potrerillos (Cuyo Basin); D-129 (Golfo San Jorge Basin) and shale plays at Los Molles, Vaca Muerta, Agrio (Neuquén Basin), Cacheuta (Cuyo Basin), and D-129 (Golfo San Jorge Basin). This paper discusses aspects of water logistics necessary during the well completion phase, fracture treatment designs applied within these various unconventional reservoirs, and laboratory studies performed on flowback and produced waters to help evaluate their potential for use and/or reuse. The primary focus here will be related to various parts of the water cycle for these projects. Stimulation and water sources are presented as detailed information concerning the type of stimulation performed in these reservoirs, volume of water, treatment types, fracturing fluids, additives used, and physical-chemical characteristics of various freshwater sources used. Logistics are discussed for water storage and transport for single and multiple well pads. Reuse of flowback and formation water addresses laboratory testing of various flowback and formation water and/or blends (freshwater and flowback water), treated and untreated including: –Physico-chemical characteristics of water (flowback and produced) from various wells. –Formation sensibility testing with flowback water from various tight and shale formations and usage possibilities. –Impact on proppant packs of floculants generated in nontraditional waters at various pH values. –A new low-residue CMHPG-metal crosslinked fracturing fluid formulated using no traditional water, i.e., untreated with high total dissolved solids (TDS).
- South America > Argentina > Patagonia Region (1.00)
- South America > Argentina > Patagonia (1.00)
- South America > Argentina > Neuquén Province > Neuquén (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Treatment (0.88)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Los Molles Formation (0.99)
- South America > Argentina > Patagonia > Golfo San Jorge Basin (0.99)
- (8 more...)