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Dash, Timothy (W.D. Von Gonten & Co. Petroleum Engineering) | Ali, Safdar (W.D. Von Gonten & Co. Petroleum Engineering) | Ali, Mansoor (W.D. Von Gonten Laboratories) | Chin, Brian (W.D. Von Gonten Laboratories) | Mathur, Ashish (W.D. Von Gonten Laboratories) | Hartanto, Ricardo (Consultants) | Ravi, Vivek (Consultants)
ABSTRACT Understanding the volumetric concentrations of hydrocarbon and water in a producing reservoir is a critical component of predicting well performance, designing well placement and field development planning. Core testing procedures and petrophysical models in unconventional shale reservoirs have always faced the challenges of establishing representative in-situ water and hydrocarbon saturations. When using existing techniques of core calibrated petrophysics, actual well production often varies significantly from expectations. These variations may include scenarios such as lower overall oil production or strong oil production that is accompanied by large volumes of produced water. This has a serious impact on the development of major U.S. unconventional plays such as the Wolfcamp, Spraberry Shale, Austin Chalk, Eagleford, among many others. Core taken from these formations is the key to better understanding what fluids are present and in what quantities. It is well agreed upon that changes in pressure and temperature as rock is taken from downhole, handled and transported to a laboratory facility affect the contents of the pore system. This generally results in a varying amount of void space that is measured in the rock at the lab. Standard practice calls for treating this void space as previously occupied by oil that has volatized during coring operations, transport, and core testing. Therefore, estimates of hydrocarbon filled porosity are made using the volume of oil extracted from the rock during testing (whether thermally or via solvents) combined with the volume of void space measured. Water Saturation is assigned a value based on the actual water measured from the rock during the extraction process. However, fluid phase behavior in nano-pore systems is not very well understood. Pore wettability and permeability are also important factors that may control what fluids are lost from the system. Given these uncertainties, the assumption that void space is associated with volatized hydrocarbon does not hold true. Through updated procedures and use of new equipment, it has been shown that a significant portion of this void filled porosity is occupied by formation water at reservoir conditions. The discussion below will show several experiments validating this idea including: comparisons between preserved and non-preserved core samples, re-testing old core to measure fluid changes with time, nuclear magnetic resonance (NMR) scans, flow-through and fluid imbibition studies among others. Where available, NMR T1-T2 logs will be used as a downhole water saturation reference. Additionally, log interpretations calibrated to this new water saturation will be shown and compared to well performance.
Barnes, Colton (W.D. Von Gonten Laboratories) | Ali, Safdar (W.D. Von Gonten Laboratories) | Mathur, Ashish (W.D. Von Gonten Laboratories) | Chin, Brian (W.D. Von Gonten Laboratories) | Belanger, Chad (W.D. Von Gonten Laboratories) | Treadwell, Justin (W.D. Von Gonten Laboratories)
ABSTRACT Oil-rich shale formations have gained a lot of prominence in recent years. A major challenge in modeling and predicting production behavior from liquid rich shale reservoirs is the absence of reliable effective permeability or relative permeability values to the flow of water and oil. We have designed an experimental setup to carry out steady state liquid permeability measurements on shale plugs at reservoir conditions of overburden stress, pore pressure and temperature using liquid hydrocarbon fluids and brines, while monitoring their relative saturations in a high-field 3D gradient equipped 12 MHz NMR spectrometer. The experimental technique begins with carrying out as-received NMR scans on shale core plug samples to measure the amount of water and oil in the samples. Micro-CT scans are used to identify and reject plug samples that have micro-cracks. These samples are then saturated with hydrocarbons, and/or brines through a combination of vacuum-assisted spontaneous imbibition, pressure and temperature. Following saturation, NMR scans are done to find the saturation of the liquid hydrocarbon and water in the sample. The samples are then loaded in an overburden cell which does not have an NMR signal. As the sample is brought up to reservoir conditions of overburden stress and temperature, hydrocarbon fluid is injected in the cell from one side of the plug while keeping variable backpressure on the other end. During the whole process, injection flow rates are continuously monitored along with upstream and downstream pressures to compute permeability. Hydrocarbon fluid permeability can also be measured after saturating or injecting brine in the sample. This measurement is similar to a relative permeability measurement of liquid hydrocarbons in the presence of water saturation, which is accurately monitored using the high-field NMR setup. The same can be done to establish brine effective permeability by injecting brine through an as-received plug pre-saturated with brine. The novel process has also been used to perform liquid pressure fall-off tests and shut-in tests on shale plugs in order to simulate actual field reservoir engineering PTA routines. This apparatus is capable of going to 10,000 psi in confining pressure, 9000 psi of pore pressure and temperatures up to 100°C. Flow rates as small as 0.00001 ml/min can be measured, and single digit nano-Darcy permeability values have been measured. Tests have been run with produced dead crude, reformulated live crude, decane and produced brines. These measured permeability values have been successfully used in reservoir simulation studies in multiple unconventional shale plays such as the Wolfcamp, Eagleford, Vaca Muerta, Austin Chalk, Niobrara, etc.
Hazlett, W.G. (Gemini Solutions, Inc.) | Snow, P.W. (Mosbacher Energy Co.) | Von Gonten, W.D. (W.D. Von Gonten & Co.) | Glasgow, W.M. (Mosbacher Energy Co.) | Banks, R.J. (Mosbacher Energy Co.) | Duncan, C.S. (Worley International, Inc.)
Abstract This paper describes the characteristics of and development plans for the PY-1 concession, a gas reservoir contained in a natu rally-fractured granite formation. Over a several-year period, exploration and delineation wells were drilled offshore India. The paper covers all aspects of the integrated geoscience/engineering development study, including seismic, core and fracture analyses, well logging, well testing, and reservoir simulation. In addition, we include the offshore facilities, pipeline and onshore compression plans. The develop ment plan was prepared by a team of engineers and geoscientists made up of both operating company personnel and contract and consulting personnel. The result of the study is a development plan for a granite reservoir. We conclude that highly-fractured granite formations should not be overlooked as potential reservoirs. This granite reservoir should provide a steady gas supply to any one of several commercial manufacturing facilities planned for the area. Introduction and Exploration History The PY-1 Field is located in the northern offshore part of the Cauvery Basin, Southeast India. The field is located offshore at a location 18 kilometers due east of the town of Porto Novo and 30 kilometers southeast of the town of Cuddalore. Water depth varies, but most of the field is in less than 75 meters of water. The PY-1 field was discovered by the India's Oil and Natural Gas Corporation Ltd. (ONGC) in 1980. subsequent to the discovery, ONGC drilled a number of wells on the structure and identified it as a fractured granite basement gas reservoir. In 1995, a 25 year Production Sharing Contract was signed between the Government of India and the PY-1 Consortium currently made up of the following partners: Mosbacher India, L. L. C., Operator, Energy Equity Corporation and Hindustan Oil Exploration Company. In 1997, the Consortium drilled an appraisal well, PY-1–12, in order to perform a long term produc tion test to establish reservoir performance and areal extent, obtain conventional core of basement reservoir for reservoir characterization, obtain quality logs for reservoir characteriza tion, and establish low known gas depth for the basement reservoir. In the remainder of this paper, we detail the results of a comprehensive study to determine the potential of this field and the facilities necessary to profitably produce the reserves. Geophysics Four 2D seismic surveys have been acquired since 1976. Some of these have been reprocessed. Vintage data quality varies between poor and good. The Top of Basement reflector occurs between 1.4 and 2.4 seconds two-way travel time in the majority of the PSC area, however, reflectors up to 4.0 seconds occur on the downthrown sides of the major bounding faults. A number of wells in the area have velocity data that is available. Average velocity to Basement is approximately 2050 mps. Geology The structure is sealed by Cretaceous to Eocene aged shales. The productivity of the reservoir comes from intense natural fracturation, brecciation and some matrix porosity influenced by massive regional intersecting faults bordering the PY-1 Conces sion Area. The PY-1 Field is a gas accumulation within a Precambrian granitic reservoir on the crest of basement ridge known as the Porto Novo Horst. This NE-SW oriented ridge is an offshore extension of Kumbakonam-Madanam-Shiyali Ridge. Intense fracturing and brecciation of the PY-1 Field basement reservoir rock is attributed to wrench tectonics during Cretaceous and Tertiary periods. The productive interval is contained in the top of a granitic basement high which has been deeply weathered, highly fractured and brecciated to form the reservoir. The high amount of fracturing has created sufficient porosity and perme ability for excellent gas reservoir quality.
Abstract Logging-while-drilling (LWD) acoustic imaging technology emerged in the past few years as a low-cost solution to detect and characterize fractures in high-angle and horizontal wells. This type of imaging tool works in either water-based or oil-based drilling fluids, making it a competitive choice for logging unconventional shale wells, which are often drilled with oil-based mud. With high-resolution acoustic amplitude and travel-time images, fractures, bedding planes and other drilling-related features can be identified, providing new insights for reservoir characterization and wellbore geomechanics. The quality of LWD acoustic images however is directly affected by drilling parameters and borehole conditions, as the received signal is sensitive to formation property and wellbore changes at the same time. As a result, interpretation can be quite challenging, and caution needs to be taken to differentiate actual formation property changes from drilling-related features or image artifacts. This paper demonstrates the complexity of interpreting LWD acoustic images through multiple case studies. The examples were collected from vertical and horizontal wells in multiple shale plays in North America, with the images logged and processed by different service companies. Depending on the geology and borehole conditions, various features and artifacts were observed from the images, which can be used as a reference for geologists and petrophysicists. Images acquired with different drilling parameters were compared to show the effect of drilling conditions on image quality. Recommendations and best practices of using this new type of image log are also shared.
ABSTRACT Rock brittleness and total organic carbon (TOC) are two essential parameters that are needed to evaluate unconventional reservoirs. Brittleness is a crucial rock physics property that is used to guide both completion and hydraulic-fracturing designs. The brittle shale is more likely to be naturally fractured and more likely to respond well to hydraulic fracturing. Ductile shale, on the contrary, is more plastic, absorbs energy, and is not considered neither a good producer nor a desirable hydraulic-fracturing interval. In such cases, formation tends to heal any natural or induced fractures. Thus, intervals with high brittleness are considered a good candidate for hydraulic fracturing. However, many authors argue that this viewpoint is not reasonable because rock brittleness is not an indicator of rock strength and the current brittleness indices are based on elastic modulus or mineralogy. Brittle rock just has shorter plastic deformation, and it is not certain that it is easier to fracture brittle rock than ductile rock since brittle formation may have greater strength than ductile formation. TOC is the measure of the total of carbon present in an organic compound and is usually used as an important factor for unconventional shale resources evaluation. In this study, we show an application of estimating total organic carbon (TOC) in a Khataba play from the triple combo logs using curve fitting. This paper also presents a brittleness model that uses the triple combo log. Logging and laboratory core testing data were collected from Khataba shale wells in Egypt. Laboratory testing was conducted to understand the complex rock mineralogical composition. Geomechanical rock properties derived from analysis of full-wave sonic logs and core samples were combined to develop sophisticated models to verify the principle of brittleness and fracability indices and to demonstrate the process of screening hydraulic-fracturing candidates. Tensile and compressive strength tests are conducted to understand rock strength better. Once the data were available, different methods were used to calculate brittleness index considering the effect of mineralogical composition and elastic moduli.