Sharma, Anoop (Schlumberger) | Yates, Malcolm E. (Schlumberger) | Pope, Tim (Schlumberger) | Fisher, Kelvin (Endeavor Energy Resource LP) | Brown, Randy (Endeavor Energy Resource LP) | Honeyman, Les (Endeavor Energy Resource LP) | Bates, Bradley (Endeavor Energy Resource LP)
Horizontal wells present a great opportunity for maximizing the potential of unconventional resource play developments by providing enhanced reservoir contact but also pose many 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 the horizontal well development in the Delaware Basin located in Reeves County, Texas. By undertaking a vertical well pilot logging program the acreage was logged 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 geosteered using a rotary steerable system 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 for 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.
For a holistic characterisation of fine-grained unconventional reservoirs, our integrated approach utilises coherent, reproducible datasets and refined work practices carried out within a comprehensive quality management system. A typical reservoir characterisation includes integration of sedimentological, structural and pore-scale datasets, however, the specific work flow design depends entirely on the nature of the problem and the availability of appropriate data.
This paper illustrates an example of unconventional reservoir characterisation of a fine-grained formation from the North Sea where the specific aims were to establish the depositional framework for recognising sedimentary environments, recommend sample locations to target specific queries within the sedimentological context for petrographical and geochemical analyses, to investigate what porosity types are present and to assess 'brittleness' of the rocks.
First and foremost, high-resolution interpretative graphic core descriptions were carried out at 1:24 scale, utilising Badley Ashton's mudrock-specific lithotypes and depositional packages schemes. Lithotype characterisation uniquely captures very fine-scale attributes (bed to subbed scale), whilst upscaled depositional packages (bed-stack scale) provide a more holistic characterisation from core, as well as from wireline and image logs, where available. Plugs coded by the above descriptors were selected post-logging, for detailed petrographical and geochemical analysis including Rock-Eval pyrolysis within the sedimentological/structural context. Mineralogical data was acquired by whole-rock and clay-fraction XRD analysis, whilst pore-scale fabric/textural investigation were undertaken by conventional light microscopy and BS-SEM. A subset of the plugs was subjected to FIB SEM analysis to characterise any potentially organic matter associated pore system. All these different strands of data were then integrated to evaluate and link the depositional system/sedimentary environment, storage capacity and brittleness of the reservoir in order to assess the overall reservoir potential of the fine-grained formation.
Wuestefeld, P. (RWTH Aachen University) | Hilgers, C. (RWTH Aachen University) | Koehrer, B. (Wintershall Holding GmbH Germany) | Hoehne, M. (RWTH Aachen University) | Steindorf, P. (RWTH Aachen University) | Schurk, K. (RWTH Aachen University) | Becker, S. (RWTH Aachen University) | Bertier, P. (RWTH Aachen University)
Upper Carboniferous sandstones in NW-Germany consist of thick successions of cyclothems and are major tight gas reservoirs. This study presents the heterogeneity exposed in a large quarry near Osnabrueck, Germany, which contains faulted and jointed third-order coarse- to fine-grained tight sandstone cycles separated by anthracite coal seams. First, we characterize the rocks and the lateral variation of rock properties such as porosity, diagenesis and structural inventory. Than we test whether the quarry may act as a reservoir analog to better constrain input data for reservoir modelling.
The tight sandstones are intensely compacted and cemented with quartz and generally characterized by low matrix porosities < 8 % (He-pycnometry on plugs and cuttings) and very low permeabilities (<0.01 mD). Porosity is generally secondary, formed by detrital and authigenic carbonate dissolution and dissolution of feldspars. Matrix porosity significantly increases up to 25% in corridors around faults. Rock types can be distinguished by spectral gamma ray in the quarry. Fluid flow within and around faults is indicated by quartz veins and fault mineralizations. Normal faults show and bands of clay smear and gouge, forming compartments. Fractures were analyzed in a 50 x 50 m section of the quarry wall using Lidar laser scanning. This digitized quarry face also allows the characterization of the lithology and quantitative measurement of bedding, fracture and fault orientation data in inaccessible areas.
Our high resolution field analog enables a better understanding of unconventional reservoir properties and reservoir quality at a subseismic scale, considering both the change of porosity during diagenesis and the formation of structures. Results may be used to develop data-driven exploration strategies and improved development options for similar subsurface tight gas reservoirs.
Coring with sponge liners is not a new technology. In some form it has been an industry offering for over twenty years but has been plagued by problems. The objective of sponge coring has been to determine separate in-situ oil and water saturations of the formation materials. The problem has been that the fluids would be expelled and lost from the core by expanding gas while bringing it to the surface, or by flushing due to filtrate invasion.
The solution to the problem has been to surround the core with a special oil absorptive (oleophilic) sponge material to capture the expelled oil and hold it in place for laboratory analysis. The challenge was to have the sponge fit tightly around the core to prevent confusing fluid migration and mud contamination in the sponge-core clearance annulus, and yet not experience core jamming and sponge damage.
Now a new, much more accurate sponge liner coring service has now been launched showing promising results. A balance seems to have been achieved between smooth core entry and a tight fit, 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.
In late 2012 Chevron utilized this new and previously unproven system to core nearly 300 ft. of sponge core in Lea County, 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 which cut a tight-clearance core provided exceptional results with an average ROP of 10.4 ft/hr, 100% core recovery and observable oil saturation in the sponge; this indicates that the system worked as designed. This case study will be described in detail within this paper.
A integrated gas production system from methane hydrate layer by circulating hot water using a pair of dualhorizontal wells has been proposed. In the system, a dissociated region including the dual horizontal wells filled with hot water, named as hot water chamber, was generated to produce gas continuously. The gas production rate has the maximum peak just after breakthrough of injected water between dual horizontal wells, then it declined and gas was produced by almost constant rate. We have successfully developed the numerical model, and matched the history of physical gas production. Moreover, numerical simulations of gas production by the hot water injection into a Nankai Trough sediment layer model using a pair of dual horizontal wells 500m in length were carried out for a methane hydrate reservoir of 20 m in layer thickness, 46% of average methane hydrate saturation, 100 and 25 md in horizontal and vertical absolute permeabilities,
respectively. The cumulative gas production is simulated as 5×106 std-m3 for initial two years. Furthermore, a new gas production scheme, which uses four pairs of dual horizontal wells in radian arrangement in a methane hydrate sediment layer with area of 1km×1km located at Nankai Trough, has been presented and evaluated with the numerical simulation as the cumulative gas production for 15 years is 1.3×108 std-m3.
Resource plays present unique challenges. These large, continuous accumulations need to be assessed by mapping out variations in risks and prospectivity that divide the resource play fairway into discrete, contiguous segments. For the resource plays - such as shale gas, shale oil, Coal Bed Methane, the challenge is economic recovery. The assessment challenge is the same: Modeling how the resource play is explored and exploited.
Given the current focus on liquids, the challenge for shale-based resource plays is assessing the potential for shale oil in resource plays where there is most often both shale gas and shale oil.
This paper extends earlier work by applying an activity based model to exploration and exploitation of a shale based resource play. The model used a segmentation of the resource play into three types of areas: shale oil, shale gas and transition zones with uncertain proportion of shale oil and shale gas. The assessment model also includes learning and the relative impact of alternative completion solutions. The model generates stochastic performance metrics that capture alternative outcome scenarios, economic returns and the delivery schedule of production and reserves.
The performance metrics support both project-level and portfolio-level decisions related to resource plays. Project-level application is illustrated using data from an Eagleford-type resource play.
Indonesia according to research by Resource International Inc. Advance. (ARII) along with the Directorate General of Oil and Gas has potential reserves (resource) 453 TCF of CBM which is divided into 11 (eleven) basin on the island of Sumatra, Borneo, Java and Sulawesi. The results of CBM product is expected to be a solution to potential energy shortages Indonesia in the future relying on energy sources from oil and natural gas.
The utilization of CBM in Indonesia following the fiscal term of Production Sharing Contract (PSC) with a validity period of 30 years. CBM reservoir characteristics that are different from conventional gas permeability which has a smaller, predominantly gas adsorbed and the under-saturated conditions require draining the water content (dewatering) before the production period that requires careful planning to produce a viable project either in terms of technical, economic and commercial.
Simulations conducted in the field SUMBAGSEL in southern Sumatra, Indonesia, seeking development planning optimization by creating scenarios drilling CBM wells with a certain amount of accumulation to get a good view of the economic indicators of Net Present Value (NPV), Internal Rate of Return (IRR), profitability index (PI) and Payback of Time (POT). The results showed that CBM development can not be done with conventional gas development model approach which uses chuck management system to control the production, while the properly management is required in the development of CBM drilling where the number of production wells will be proportional to the increase of production. Knowledge of reservoir characteristics and production optimization management of the number of drilling development wells during fiscal term contract with the production sharing contract will result in the economic development of CBM.
The exploration of shale gas resources in Europe is moving at a slow pace, despite the fact that drilling for reservoir characterization is essential for any further planning. Whether shale gas development in certain regions is economically feasible at all and what such development activities might entail can’t be determined in the absence of critical data. Yet, there is widespread public resistance that influences political decision making and permitting, and that sometimes doesn’t even allow for exploration. Most of the stakeholders concerns are related to perceived environmental risks for water by hydraulic fracturing. Main themes are concerns about the contamination of water resources by fracturing chemicals, methane or flowback water, or concerns about the depletion of groundwater and surface water. While some of the perceived risks may be overestimated or unsubstantiated, there are real risks that have to be addressed by thorough assessments of the environmental, health and social impacts, and by an integrated approach to water management from sourcing to final discharge. This includes the transportation and distribution logistics for water and wastewater movements. It is essential to establish relevant reference and baseline data on groundwater and surface water systems well ahead of project implementation, to assess risks in a fashion that is understood by interested stakeholders, to define proactive and reactive resource protection measures, and to monitor performance. This paper suggests an integrated approach that combines the elements of impact assessments, scientific and technical data gathering, and the monitoring of potential impacts across the life cycle of a shale gas project, along with communication strategies that satisfy stakeholder needs. It also discusses the benefits of quantitative risk assessments in improving the credibility of proposed exploration and development activities.
Description of the material:
After more than a decade of successful shale development, many of the pre-conceived ideas about these unconventional reservoirs can be revisited. One notion was that a long horizontal well should produce more hydrocarbons than a short one. Data from different shale basins showed that this is not the case and in many instances, shorter laterals have outperformed longer ones. Although innovative completion and fracing strategies have played a major role in optimizing well performance, these technologies are not able to explain the wide variations in shale well performance.
This paper describes the unique characteristics of the distribution of shale well performances and how good shale well productivity exhibit a log normal distribution that seem to be controlled mainly by the natural fracture system. These shale performances seem to be related mostly to the Shale Capacity defined as the product of four key shale drivers: Total Organic Content, Porosity, Brittleness, and Natural Fracture Density. When drilling a shale reservoir, it appears that the Relative Intercepted Shale Capacity (RISC), seems to have a strong correlation with the resulting relative well performance
Well productivity in shale reservoirs could be predicted in a relative sense with reasonable accuracy if the 3D shale capacity model is available to the operator. Additionally, the availability of the Shale Capacity volume allows the proper selection of appropriate number of laterals, their landing zone, and the intervals to be completed.
Results, Observations, and Conclusions:
These concepts are illustrated with a Marcellus example where with very limited well data, newly drilled well performances are predicted from the Shale Capacity and Relative Intercepted Shale Capacity (RISC) which correlates very well with existing well performances.
Significance of subject matter:
Quantitative link between G&G and shale well performance.
In the Vaca Muerta shale located in the Neuquén basin, Argentina, the most prolific intervals tends to be the most difficult to hydraulically fracture due to 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.
This paper presents a case history where a calibrated, anisotropic 1D mechanical earth model (1D MEM) was developed and used in developing an optimized 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 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 on the well. This formed the basis for selecting the optimum number of stages and perforation strategy on the well.
Sensitivity analysis revealed the impact of the hydraulic fracture properties on the production performance, e.g. higher fracture conductivity greatly improves the well performance in the deeper Vaca Muerta intervals, while 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 eventually planned, but due to casing limitation, only the first stage was eventually executed. A time-lapse acoustic measurement acquired on the well corroborated the propped fracture height predicted during the completion design phase.
This example illustrates how 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.