This paper investigates the gas production source of the Standard Draw Field in the Greater Green River Basin (GGRB) in Southern Wyoming in Townships 17, 18, 19, and 20; Ranges 92 and 93. The study was initiated to eliminate the speculation that the sole producer of all the gas in the Standard Draw Gas Field is the Almond Bar Sand. Detailed analysis of the OGIP and future production of the Almond were examined by three methods; the volumetric method, material balance equation, and decline curve analysis. The volumetric analysis yielded an OGIP of 1245 Bscf. The material balance analysis yielded an OGIP of 624 Bscf. Decline curve analysis yielded an EUR of 870 Bscf using an economic abandonment rate of 27000 Mscf. Consequently all the gas being produced can come from the Almond Bar Sand. Introduction The Standard Draw Gas field located in the Greater Green River Basin (GGRB) between Rock Springs and Rawlins produces from the Almond bar sand in the Upper Cretaceous Mesaverde group. The sand has been very productive and it has been postulated that the sand is connected by fractures to lower sands and hence is draining much more than the bar sand. The current project attempted to analyze the total field data by volumetrics, material balance and decline curves to examine the hypothesis on a broader scale. Over millions of years gas has migrated to the top of the Mesaverde group where it has been trapped by threshold displacement capillary pressure. The source of gas located through out the Mesaverde group was deposited from a shell/barrier island system. It is assumed that most of the gas has migrated up to the point where it cannot overcome the capillary pressure. In tight sands the capillary pressure is greater than the gas migration forces. Therefore to push the water through the pore spaces in a tight sand reservoir the viscous forces must be greater than the capillary forces. In the late 1970s natural gas began being produced from the Almond formation which is near the top of the Mesaverde group. The upper and lower Almond sand has a productive depth range between 3500 to 12500 feet. The Almond varies in thickness between 0 and 800 feet. These pockets of gas, which have been called "sweet spots," were discovered in the Almond Formation of the Wamsutter Arch in the Washakie Basin area in T17 R93, T18 R93, T19 R93, T20 R93. The Almond outcrops along Rock Springs in the West and Rawlins uplifts to the East of Wamsutter Arch. The deepest point of the Almond is 13000 feet in the Washakie Basin. On the Wamsutter Arch, the productive zones are between 8500 to 10000 feet. The thickness of the Almond Bar Sand associated with the Wamsutter Arch varies from 0 to approximately 30 feet and has an extended area of 162 square miles. Production data was gathered within the 162 sq. mi area to determine the size of the reservoir. Data was compiled from logs obtained from the Oil and Gas Commission of Wyoming and Wyoming Geological Survey. The log data was used to determine the thickness and the porosity of the formation. Log data was also compiled from Petroleum Information (P.I.) publication. The P.I. data was used to determine the decline of production. This information gave the decline rate of the reservoir. Another form of data compiled was bottom-hole pressures and compressibility factors. A graph of P/Z versus the cumulative production was created. This was extrapolated to zero pressure to obtain the initial gas in place of the reservoir. Control Volume Determination The cumulative production data from the wells located in the 162 sq. mi. study area was employed to located the area of highest gas production. P. 195^
ZADCO's new field development program calls for drilling extended reach wells from artificial islands with the borehole kicking off at shallow depths and holding high inclination angles through the overburden. Previously, the development plan relied entirely on short reach, horizontal development wells drilled from jackup rigs with shallow overburden borehole sail angles rarely exceeding 30°. For both types of wells, bentonite weighted sea water is the preferred drilling fluid for the 16″ or 17.5″ diameter holes. Drilling problems that were managed in low-inclination wells became exacerbated at higher angles causing significant rig non-productive time (NPT). To improve our understanding of the shallow overburden formations, a comprehensive logging program was conducted in a key well drilled with a potassium chloride (KCl) mud system. Wireline borehole image, dipole shear sonic, spectroscopy and neutron-density-resistivity triple-combo logs were used to characterize the formations. A successful logging program relies on maintaining the borehole in good condition. In this case, the KCl mud in conjunction with good drilling practices kept the hole near the 16″ bit gauge for 90% of the interval. Drilling mud losses were also minimized. The logging tools were successfully run to T.D. and the data acquired. The mineralogy of the penetrated formations was accurately quantified using spectroscopy tools. A high-resolution resistivity image log revealed that the entire interval was weakly fractured with a few zones of high secondary porosity and conductivity. These zones correlated well with zones of similar characteristics in offset wells. The key to drilling a high angle well lies is the geomechanical / geochemical characterization of the overburden formations to determine the wellbore failure mechanism(s). This paper highlights the benefits of a KCl mud in the top hole and the results of advanced logging covering the predominately shallow carbonate formations that exist above a large carbonate reservoir. It emphasizes the need for characterizing not only the reservoir but the overburden formations. This advances drilling engineers’ understanding of formation characteristics so that increased drilling sail angles could be achieved through the shallow overburden and thus successfully reach the reservoir targets.
A pilot was drilled offshore Abu Dhabi aiming to determine the in-situ stress magnitudes. A time-dependent reactive shale formation separates Middle and Lower Cretaceous Limestone formations, leading to difficult open-hole logging conditions. Determining the stress regime and stress contrast across these formations is critical for assessing wellbore stability in extended-reach wells, setting casing shoe depths, and designing hydraulic fracturing in the tight reservoirs. Therefore, a comprehensive logging including multiple in-situ stress measurements and full-core was acquired. Seven microfrac stress measurements were obtained in one pipe-conveyed straddle-packer run conducted in a 15°-degree deviated 8½-in. open-hole wellbore. Each microfrac test was designed with multiple pressurization cycles to accurately obtain the closure stress away from the near-wellbore zone. Core and logging data from offset wells were used to calibrate the pre-job microfrac assessment. Real-time data monitoring was implemented for quality-control and tool operation decisions while logging. Three different pressure-decline analysis methods were used to identify the fracture closure: (i) SQRT square-root of time, (ii) G-function, and (iii) Log-Log plot on each microfrac station. The pilot well required an inhibited oil-based mud system to stabilize the 360-ft. water-sensitive shale formation. All microfrac stress measurements successfully reached the formation breakdown pressure, providing clear propagation and fracture closure identification. The three pressure decline methods produced results around ± 15 psi from each other with G-function predominately higher and Log-Log predominately lower than the SQRT. These microfrac tests measured minimum horizontal stress gradients between 0.67 to 0.77 psi/ft confirming the normal faulting stress regime in the studied reservoirs and a near strike-slip stress regime in the intervening shale formations. The formation breakdown, fracture reopening and closure pressure provide an accurate present-day tectonic model with ~0.1 and ~0.9 mStrain in the minimum (N80°W) and maximum (N10°E) horizontal stress directions in the absence of breakouts and induced fractures on image logs. The Lower Cretaceous tight reservoirs, identified as generally thin (<10-30ft) and low-quality (<10mD, locally <1mD) microporous carbonates, were located between low stress contrast (0.69 psi/ft) clay-rich limestones intervals in the overburden and high stress contrast (0.74 psi/ft) denser dolomites and clean tight limestones in the underburden. The risk of tool plugging and unsuccessful latching due to large particle solids in the mud was mitigated by multiple mud filters and repeated circulations while running-in hole with the straddle packer module. The microfrac tests in the Lower Cretaceous tight reservoirs provide the stress contrast measurements to properly evaluate hydraulic fracture containment on these tight reservoirs for future field development plans.
Thin layering and micro-fracturing of the thin laminated layers are some possible reasons for the wellbore stability problems of the Nahr Umr shale. If the drilling fluid density is too low, collapsing of the borehole is possible, and if the drilling fluid density is too high, invasion of the shale can occur, weakening the shale, making boreholes prone to instability. These effects can be semi-quantified and assessed through the development of a geomechanical model. The application of a geomechanical model of a reservoir and overlaying formations can be very useful for addressing ways to select a sweet spot and optimize the completion and development of a reservoir. The geomechanical model also provides a sound basis for addressing unforeseen drilling and borehole stability problems that are encountered during the life cycle of a reservoir. Key components of any geomechanical model are the principal stresses at depth: overburden, minimum horizontal principle stress, and maximum horizontal principle stress. These determine the existing tectonic fault regime: normal, strike-slip, and reverse. Additional components of a geomechanical model are pore pressure, unconfined compressive strength (UCS) rock strength, tilted anisotropy, and fracture and faults from image logs and seismic. Unfortunately, models used to make continuous well logging depth-based stress predictions involve some parameters that are derived from laboratory tests, fracture injection tests, and the actual fracturing of a well—all contributing to the uncertainty of the model predictions. This paper addresses ways to obtain these key parameter components of the geomechanical model from well logging data calibrated to ancillary data. It is shown how stress, UCS, and pore pressure prediction and interpretation can be improved by developing and applying models using wellbore acoustic, triple combo, and borehole image data calibrated to laboratory and field measurements. The nahr umr shale and other organic mudstone formations exhibit vertical transverse isotropic (VTI) anisotropy in the sense that rock properties are different in the vertical and horizontal directions (assuming non-tilted flatbed layering), the horizontal acoustic velocity is different from that of vertical velocity. This necessitates the building of anisotropic moduli and stress models. The anisotropic stress models require lateral strain, which as shown in the paper, can be obtained from micro-frac tests and/or borehole breakout data.
Over the course of drilling wells in one of ADNOC Offshore fields, there have been numerous endeavors in the Crestal region of the field with each well presenting its unique array of issues and challenges related to well construction, stability and delivery. Even while drilling two identical wells with extremely similar well designs and architecture, the wells encountered different and at times opposite responses from the formations being drilled. This resulted in the well construction becoming more problematic than expected in some cases while in others the situation was completely opposite, thus drilling and well construction went extremely smooth delivering the well ahead of time as opposed to the nearby sister well. While the denominators may be segregated based on commonality and differences, there is one particular aspect of the drilling process and planning that has been significantly overlooked, the Azimuth of the well particularly in the crestal region of the field. Over the years, investigation into the well trajectory, the well fluids and intrinsic properties have been dissected to arrive at a result but has not produced the expected success. The Azimuthal impact on the resultant seems to have been ignored to the extent of not understanding the Azimuth impact on a well trajectory. It is of paramount importance to investigate and identify the imp act since the related stresses and their directions directly define and drive the stability and the optimal mud weight needed to drill successful wells.
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