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Collaborating Authors
Texas
Horizontal Well Development in Unconventional Resource Play Using an Integrated Completion and Production Workflow: Delaware Basin Case Study
Sharma, Anoop (Schlumberger) | Yates, Malcolm E. (Schlumberger) | Pope, Tim (Schlumberger) | Fisher, Kelvin (Endeavor Energy Resources LP) | Brown, Randy (Endeavor Energy Resources LP) | Honeyman, Les (Endeavor Energy Resources LP) | Bates, Bradley (Endeavor Energy Resources LP)
Abstract Horizontal wells give a great opportunity for maximizing the potential of unconventional resource play developments by providing enhanced reservoir contact but present multiple challenges in the process due to the heterogeneous nature of the unconventional reservoir rock. This study covers the implementation of an integrated completion and production workflow to optimize a horizontal well development project in the Delaware Basin located in Reeves County, Texas. By undertaking a vertical well pilot logging program, the acreage was evaluated for petrophysical and geomechanical properties using advanced geo-chemical and full-wave sonic tools to quantify reservoir quality (RQ) and completion quality (CQ), respectively. Detailed fracture simulations were performed at multiple depths to locate the optimum landing point that maximized reservoir contact. Incorporating the key findings of the wellbore stability analysis, the well was geo-steered using a rotary steerable system (RSS) and a logging-while drilling (LWD) resistivity tool that placed 100% of the lateral in the target zone. Further completion simulations were performed to determine a perforating and staging strategy which would optimize the number of stages. The flow-channel fracturing technique, which provides a novel approach for achieving fracture conductivity, was also implemented on the studied well to significantly improve the effectiveness of the fracture stimulation treatment. Fracture diagnostics, detailed post fracture modeling, and production analysis techniques, which utilized rate-transient analysis and history matching, were performed to provide better understanding of the effectiveness of the stimulation treatments (fracture lengths/conductivity), thereby allowing further optimization of the stimulation program. This study has demonstrated how the implementation of an integrated design and evaluation workflow can optimize the overall well production performance as well as reduce drilling and stimulation costs in unconventional resource play developments.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Petroleum Play Type > Unconventional Play (0.81)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Passive Seismic Surveying > Microseismic Surveying (0.49)
- 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)
- (27 more...)
Abstract Many tight and shale-oil gas reservoirs are being explored in Argentina to increase local hydrocarbon production. As known, hydrocarbon resources in the Neuquén basin are massive; however, many are far from being developed to the degree that they can be called resources. Significant work has yet to be done to make this happen. It is also well known that large areas in the Neuquén basin are under strike-slip stress conditions that may be a strong influence on stimulation effectiveness. After analyzing the production results of several wells and their associated oil/gas fields, a hypothesis was developed that suggests a possible relationship between the tectonic framework and the location of successful wells. This hypothesis might not only explain the productivity results of some wells to Vaca Muerta shale and other tight reservoirs, but also could help in locations of new wells to help reduce investment risks and improve productivity. This analysis compares aspects from structural geology, petrophysics, and completion descriptions observed in different fields to productivity results. Information included in this paper is sufficient to improve understanding of the conditions for a good or bad well based on this hypothesis; therefore, these lessons can be applied to generate conclusions.
- South America > Argentina > Patagonia Region (1.00)
- South America > Argentina > Neuquén Province > Neuquén (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.94)
- Geology > Structural Geology > Tectonics > Compressional Tectonics (0.69)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Field > Vaca Muerta Shale Formation (0.99)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Los Molles Formation (0.99)
- South America > Argentina > Mendoza > Rayoso Formation (0.99)
- (2 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- 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 > Unconventional and Complex Reservoirs > Shale oil (0.90)
New Sponge Liner Coring System Records Step-Change Improvement in Core Acquisition and Accurate Fluid Recovery
Shale, Les (Baker Hughes) | Radford, Steven (Baker Hughes) | Uhlenberg, Thomas (Baker Hughes) | Rylance, Jon (Baker Hughes) | Kvinnesland, Audun (Baker Hughes) | Rengel, Carlos (Baker Hughes)
Abstract New sponge coring service and technology have been introduced to the oil and gas industry. Admittedly sponge coring has been an industry offering in some form for over twenty years but until now it has been plagued by chronic problems. The objective of sponge coring was to determine separate in-situ oil and water saturations of the formation materials. The problem with conventional coring has always been that the fluids would be expelled and lost from the core by the expanding gas while bringing it to the surface. The long-time solution was to surround the core with a special oil-absorptive (oleophilic) sponge material that would capture the expelled oil and hold it in place for laboratory analysis. The challenge was to fit the sponge tightly enough around the core to prevent fluid migration and mud contamination in the sponge-core clearance annulus, and yet avoid core jamming and sponge damage. This new, more accurate sponge liner coring service is now in place, showing excellent results. A balance seems to have been achieved between smooth core entry and a properly fitting, pre-saturated sponge with virtually no fluid migration. This new service cuts and provides oil-absorptive sponge-encased 3½-in. diameter core in 30 ft lengths with a maximum downhole temperature and pressure of 195°F (90° C) and 15,000 psi (1,034 bar) respectively. Special vacuum pump service equipment and sealing system are utilized to pre-saturate the sponge liner with brine. In late 2012 a major operator utilized this new and previously unproven system to core nearly 300 ft of sponge core in New Mexico, USA. The coring program used a special low-invasion coring fluid with a low spurt loss and a staged trip-out-of-the-hole schedule to minimize gas expansion/oil movement. The precision core bit that cut a tight-clearance core provided exceptional results with an average rate of penetration (ROP) of 10.4 ft/hr, with 97% core recovery and observable oil saturation in the sponge, indicating the system worked as designed. This case study will be described in detail within this paper.
- Europe (1.00)
- North America > United States > New Mexico (0.24)
- North America > United States > Texas > Permian Basin > Central Basin > Word Group > San Andres Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > North Viking Graben > Block 211/26a > Cormorant Field > Etive Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > North Viking Graben > Block 211/26a > Cormorant Field > Brent Group Formation (0.99)
- (2 more...)
Abstract Optimizing operational efficiencies in unconventional resource developments is one of the key success drivers for improved economics. In this work, an approach for exactly that problem is presented, designed for a field development scenario in Germany. Starting with a model that captures all key parameters which are influencing a development program such as the gas market and prize scenarios, political situation, environmental regulations, logistical requirements, etc., it immediately turns out that the highly complex model has to be significantly simplified and a sub-model with clear and precise boundary conditions has to be generated. This sub-model is tuned to problems of particular interest, considering technological parameters such as the impact of various state of the art drilling technologies or different fracturing methodologies on the entire development program. It is possible to identify interrelations of various procedures and allows estimating project costs. Operational scenarios can also efficiently be tested, and validated and the financial key parameters of different scenarios can be compared. Moreover, short- and long-term benefits and drawbacks of various solutions can be assessed and optimized. Also, limitations of System Dynamics for that kind of simulation are pointed out, and it is shown how to solve the problem with an Agent Based Modeling approach.
- Europe (1.00)
- Oceania > Australia (0.69)
- North America > Canada (0.68)
- (2 more...)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.57)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.46)
- Geology > Geological Subdiscipline > Geomechanics (0.46)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (7 more...)
The Bowland Shale in the Roosecote Borehole of the Lancaster Fells sub-Basin, Craven Basin, UK: a Potential UK Shale gas Play?
Hough, Edward (British Geological Survey) | Vane, Christopher H (British Geological Survey) | Smith, Nigel J (British Geological Survey) | Moss-Hayes, Vicky L (British Geological Survey)
Abstract A re-evaluation of the Roosecote Borehole, located in the northern part of the Craven Basin (northern England), places the Bowland Shale in a modern geological context and allows an improved understanding of basin evolution and shale hydrocarbon prospectivity. In northern England during the Early Carboniferous, rapidly subsiding sub-basins developed between local highs in the Craven Basin. Subsequently, during the thermal relaxation phase, a period of regional subsidence allowed thick accumulations, locally in excess of 500 m, of hemi-pelagic mudstone to be deposited as a transgressive systems tract. The Roosecote Borehole is a stratotype section for the Bowland Shale Formation, located close to the northern basin- to- shelf margin of the Craven Basin. The upper part of the Mississippian (Lower Carboniferous) Bowland Shale Formation is the principal potential shale gas play in the British Isles. The Bowland Shale and other argillaceous units of the Craven Group are rich in organic matter, have a similar depositional style to coeval units in the USA including the world-class Barnett Shale of the Fort Worth Basin, Texas, USA. Throughout England, Wales and Ireland it is currently being investigated by several exploration companies, with at least 4 dedicated shale exploration wells now drilled. Rock evaluation indicates the TOC at between 1.73 – 3.72 %. Many samples indicate a mixture of type III and IV kerogens; there was no evidence for type I or II kerogens found. Thermal maturity for the sequence is within the oil window, with results indicating liquid oil and wet and dry gas have been generated. However, an estimate of the organic matter transformation ratio of 0.36 (36% kerogen conversion to hydrocarbons being possible) compares poorly to the Barnett Shale. Consequently we conclude that the Bowland Shale within the Roosecote Borehole has some, but possibly lower, potential as a shale oil play.
- Europe > United Kingdom > England (1.00)
- North America > United States > Texas > Tarrant County > Fort Worth (0.24)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (1.00)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- Europe > United Kingdom > Solway Basin (0.99)
- Europe > United Kingdom > England > Humber Basin (0.99)
- (5 more...)
Abstract A successful evaluation and development program in oil- and gas-bearing shales requires considerable analysis and investment, not to mention optimization to help ensure a profitable outcome. Accelerating optimization, reducing capital expenditures, and improving lifecycle net present value (NPV) for the asset are reasonable goals. Seven shale properties are key drivers to help achieve successful play economics. However, the heterogeneity of shales makes well location selection difficult without appraisal well logs and geostatistical mapping of shale property quality. The analysis method allows operators to quickly high-grade areas within a large, heterogeneous shale play using logging suites from a limited number of wellbores in the play. Further, the methodology has been extended to quantify the play's potential reward versus risk distribution for in-fill drilling investments. This study extends the method to optimizing lateral lengths of horizontal wells. Geostatistics provides a means to determine correlation lengths of aggregate shale properties known to be critical to successful economics. The correlation length is used to determine the appropriate length of the horizontal well lateral, restricting it within the highest rock quality for stimulation effectiveness and production rates. Because optimal lateral lengths can be predicted using this approach, it is now possible to pinpoint the best wellhead location, the best landing point for the horizontal portion of the well, and set the optimal length of the lateral. This reduces the drilling of unproductive lateral lengths and targets stimulations. By shortening the "trial-and-error" evaluation lifecycle stage using this methodology, an operator can develop an asset more quickly and at less cost than with previous approaches.
- North America > United States > Texas (1.00)
- Europe (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (10 more...)
Abstract In this case study we outline how microseismic analysis can be used to optimize treatment design and determine the portion of the stimulated rock volume that should be productive. To begin, microseismic data was acquired with a permanently installed shallow buried array of geophones during the hydraulic fracturing of 17 wells in the Marcellus Shale. The processed results were used to conduct a multi-disciplinary study integrating geology, geomechanics, reservoir and completion engineering, and ultimately, production data. A stress inversion from focal mechanisms was performed, and correlations were made between hydrocarbon production and microseismic results. That work, in conjunction with the variability in the stimulation approach, was used to optimize the treatment design on an individual wellbore and on a field development scale. Treatment design analysis indicated optimum wellbore spacing, stage spacing and length as well as evaluated the vertical coverage of the treatment within the Marcellus. Incorporating information from source mechanisms, an event magnitude calibrated discrete fracture network (DFN) was modeled taking into account the seismic energy of the events, rock properties, the injected fluid volume and efficiency. Evaluating the placement of proppant inside the DFN enables distinction between the part of the stimulated rock volume (SRV) that contributes to production in the long term, and the part of the reservoir that was affected by the treatment but may not be hydraulically connected over a longer period of time. Finally, the permeability of the stimulated fracture system was calculated from the microseismic results. This allows for the evaluation of the drainage volume and estimation of production.
- North America > United States > Ohio (0.54)
- North America > United States > West Virginia (0.54)
- North America > United States > Virginia (0.54)
- (3 more...)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Structural Geology > Tectonics > Plate Tectonics (0.47)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.41)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (0.38)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- (8 more...)
Sweetspotting of the First Appraisal Campaign of Unconventional Resource Play in Kuwait
Narhari, Srinivasa Rao (Kuwait Oil Company) | Al-Ashwak, Samar (Kuwait Oil Company) | Kidambi, Vijaya Kumar (Kuwait Oil Company) | Al-Ajmi, Neema Hussain (Kuwait Oil Company) | Neog, Nilotpaul (Kuwait Oil Company) | Rao, Jonna Dayakar (Kuwait Oil Company) | Makki, Musaed Yaseen (Kuwait Oil Company) | Narayan, Acharya Mihira (Kuwait Oil Company) | Erkan, Fidan (Kuwait Oil Company) | Dashti, Qasem (Kuwait Oil Company) | Darous, Christophe (Schlumberger) | Chakravorty, Sandeep (Schlumberger) | Miller, Stephen (Shell Kuwait Exploration and Production)
Abstract Organic rich Kerogen layer of Lower Kimmeridgian to Upper Oxfordian age, deposited throughout Kuwait, is a TOC rich layer with varying TOC content between 2 to 20 wt% (in the vertical section) and having an average TOC of about 8 wt%. The depth of occurrence of this layer favorably places this zone to be having potential in rich gas condensate resource in the northern part of Kuwait. This layer occurs at a depth of 14000–16000 ft with a reservoir temperature of 270°–275°F, pressure of 11000 psi and average thickness of over 50ft. This is one of the main source rocks for majority of the oil and gas fields of Kuwait. This Kerogen section is penetrated through a number of vertical wells, as part of development of deeper reservoirs in this area, which offers an excellent opportunity to evaluate this section through core and open-hole log data. Because of the strong acoustic contrast with the overlying and underlying layers, this reservoir section is a very strong mappable seismic reflector. As part of appraising the potential of this layer, as a resource play, a comprehensive success criteria has been worked out for location selection. An integration of all available geo-scientific data such as geochemical, 3D seismic attributes, petrophysical analysis, borehole image interpretations, geo-mechanical, core and mud logs has been carried out. The above data integration/analysis was combined with the success criteria, leading to selection of sweet-spots for planning the first dedicated horizontal well targeted on this layer. This paper presents the success criteria worked out and the integration of data for high grading the locale – sweet-spots, for the first set of horizontal wells for appraising this deep HP-HT unconventional play of Kuwait.
- Phanerozoic > Mesozoic > Jurassic > Upper Jurassic > Oxfordian (0.54)
- Phanerozoic > Mesozoic > Jurassic > Upper Jurassic > Kimmeridgian (0.54)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.69)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.48)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.32)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (7 more...)
Abstract Optimization of stimulation is key to successful development of unconventional reservoirs. Microseismic monitoring is the most powerful tool to help us understand where and what is happening during and after the stimulation. Yet very little is understood about the relationship between microseismicity and hydraulic fractures: some believe microseismic events are part of the hydraulic fractures, some believe they are resulting from stress changes and fluid leak-off. Microseismic datasets with accurate event locations complemented with source mechanisms lead us to a new level of understanding of the interaction between hydraulic fracturing and seismic response. There are at least four geomechanical models to explain observed failure mechanisms and the opening (or closing) of hydraulic fractures (seismic tensile opening, leak-off cloud of seismicity around the hydraulic fracture, shearing between aseismic tensile opening and horizontal fractures shearing on vertical planes). Unfortunately none of these models is consistent with observations presented in this study. Hence we developed a new geomechanical model of bedding plane slippage and vertical shearing induced by hydraulic fractures in shale reservoirs. We present a case study including detailed source mechanism inversion for a microseismic dataset from hydraulic fracturing of a shale gas play in the North America. We observe source mechanisms dominated by shear failure with dip-slip and strike-slip sense of motion. The dip-slip mechanisms are prevailingly oriented with shear planes along the maximum horizontal stress. This can be explained as slippage on beddings planes caused by aseismic opening of hydraulic fractures. The strike-slip mechanism show small but real components of non-shear deformation. This can be also explained as slippage on vertical plane perpendicular to maximum horizontal stress with slight opening as these events are direct part of the hydraulic fracture. This model explains large energy difference between seismic and hydraulic energy, and prevailing orientation of the shear planes of the induced microseismic events. In addition, the bedding planes are weak planes in the shale formation likely to fail. The model can better constrain fundamental parameters of induced hydraulic fractures and describe hydraulic fractures and their interaction with the shale plays.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- North America > United States > Texas > Sabine Uplift > Carthage Cotton Valley Field > Cotton Valley Group Formation > Cotton Valley Sand Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Willis Field (0.93)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
Abstract In the Vaca Muerta shale of the Neuquén basin, Argentina, the most prolific intervals tend to be the most difficult to hydraulically fracture because of the abnormally high fracture gradients present in some parts of the basin. Thus, it becomes very important to have a good understanding of the anisotropic geomechanical properties of this heterogeneous formation prior to developing the completion strategy. A calibrated, anisotropic 1D mechanical earth model (1D MEM) was developed and used to optimize the completion strategy for a vertical well in the Vaca Muerta shale. The output from the 1D MEM, including the principal stresses, anisotropic elastic properties, pore pressure, and rock strength, were used to define the reservoir intervals with the best characteristics for initiation, propagation, and maintenance of a conductive complex fracture network. Next, the reservoir intervals with the highest hydrocarbon generation tendency were determined from petrophysical and image logs acquired in the well. This formed the basis for selecting the optimum number of stages and perforation strategy for the well. Sensitivity analysis revealed the impact of the hydraulic fracture properties on the production performance. The analysis showed that higher fracture conductivity greatly improves the well performance in the deeper Vaca Muerta intervals, whereas larger fracture surface area is more beneficial across the shallower intervals. Thus, a unique completion strategy was developed for each interval to optimize the well performance. Three hydraulic fracture stages were planned initially, but because of casing limitation, only the first stage was executed. A time-lapse acoustic measurement acquired from the well corroborated the propped fracture height predicted during the completion design phase. The study showed that proper characterization of the anisotropic geomechanical behavior of the Vaca Muerta formation improves the development of a completion strategy, which ultimately optimizes economic performance of the well.
- South America > Argentina > Patagonia Region (1.00)
- South America > Argentina > Neuquén Province > Neuquén (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.95)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Passive Seismic Surveying > Microseismic Surveying (0.46)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- (5 more...)