The discovery of significant reserves in the Middle Bakken of the Elm Coulee Field in 2000 changed the development of Bakken Formation in the Williston Basin. In 2006 the Elm Coulee success led to the exploration of other fields in the Williston Basin, such as Parshall and Sanish fields in North Dakota. Thousands of Middle Bakken wells have been drilled and produced in the primary production mode, yet there is likely significant potential for enhanced oil recovery, which prompted this multi-facetted research study. First, the physical properties of the reservoir brine, oil, and gas of fluid samples from different Middle Bakken geographic locations are presented to emphasize significant physical property differences across North Dakota. This information is essential to understand the impact of fluid properties on primary production and potential for oil recovery at different locations. Second, we identified reservoir connectivity by combining petrographic analysis, scanning electron microscopy, and permeability measurements. The permeability measurements included core-based steady-state permeability and unsteady-state water-oil relative permeability. The selected cores were characterized using X-ray diffraction mineralogy, thin section petrology, and scanning electron microscopy (SEM) to correlate flow capacity to the petrophysical properties. The conclusion is that interconnected microfractures make current production possible in successful wells. Finally, the high salinity formation water compared to the low salinity of fracturing and IOR fluids was investigated by performing spontaneous imbibition using both low and high salinity brines. It was concluded that in the oil-wet environment of the Bakken, the low salinity injection fluids can enter part of the reservoir because of osmotic pressure while high salinity makes the clay surface extremely hydrophobic and causes local oil-wetness.
Clay stabilizers are used to prevent fines migration and clay swelling, which are caused by the contact of clays with low salinity or high pH fluids. Previously used clay stabilizers, including hydroxy-aluminum, zirconium oxychloride solutions, and cationic polymers have several drawbacks. Hydroxy-aluminum and zirconium oxychloride solutions can be leached by acids (Coppel et al. 1973). Cationic organic polymers can cause formation damage in some cases . Their environmental impact is also questionable (Patel 2009). There is a need to develop new clay stabilizers that can work with acid treatments and that are environmentally acceptable.Laboratory studies were conducted on a newly developed inorganic aluminum/zirconium-based compound. Coreflood experiments were conducted on Berea sandstone cores (1.5 in. in diameter, 6 and 20 in. in length) to assess the effectiveness of the new compound at high temperatures and determine the impact of acids on its performance. Inductively coupled plasma was used to measure the concentrations of aluminum and zirconium in the coreflood effluent samples.The new clay stabilizer was very effective in mitigating fines migration. Experimental results showed that unlike previous Al/ Zr compounds, the new stabilizer was effective even after using several 15 wt% HCl acid washes. In addition, it did not cause formation damage, and worked very well up to 300 F. It is nontoxic, with no smell, and environmentally friendly.
Novel apparatuses have been developed to measure permeability using steady-and unsteady-state methods on nano-Darcy (nD) shale (source rock) using intact cylindrical samples returned to isostatic effective reservoir stress. The steady-state method uses a high pressure dual pump system using supercritical fluids. High pressure supercritical fluids have low viscosity and low compressibility. The effect of low viscosity fluid results in measureable flow rates and the effect of low compressibility fluid minimize unsteady-state transients thereby reducing the amount of time required to achieve steady-state equilibrium. Specially designed and configured pump systems, seals and sleeves reduce leak rates to allow Darcy flow and permeability determination below 1 nD. The unsteady-state method is based upon standard designs but is optimized for small pore volume. In this report we present a summary of over 200 such permeability measurements. Permeability is observed to be dependent on geologic parameters, such as, texture and composition. Stress dependence, with hysteresis, is observed for samples with and without fractures as is rate dependent skin (Forchheimer). An interpretation model where matrix storage feeds a progressively larger fracture network provides a logical basis for a dual-porosity reservoir simulation model. This dual-porosity model is used to understand the influence of reservoir production parameters, such as choke management.An additional observed effect is possibly related to pore collapse and disconnection. Pores associated with organic matter are softer than the surrounding mineral matrix. If these pores have a sufficiently small throat diameter, it is not hard to envision that they easily compact and close under increased effective stress as the result of reservoir depletion. Therefore, organic pore systems can become isolated unlike those of a sponge where fluids remain in pressure communication at all times. The implication of such pore isolation phenomena is that fluid material balance is not preserved during production and can contribute to large production decline rates. Development of an Unsteady-State Apparatus and Methodology for Low Permeability and Porosity Shales. SummaryA device and methodology has been developed for subject purpose under axial, radial and restricted three dimensional flow geometries. The intended use for this is as input to petroleum engineering models to evaluate producing potential of gas shales and other similar geologic formations. The application of this method to radial and three dimensional is new and without, to the authors knowledge, known published literature.Motivation for this work was to develop a method which would preserve geologic rock texture at reservoir stress utilizing cylindrical plug samples as opposed to standard commercial methods which uses crushed samples without stress.An outline of the mathematical model is presented in the second appendix and examples of the history match result at high, medium, and low permeability are shown in the below ex...
In 1993, Shell began a cooperative evaluation with the Gas Research Institute to study factors controlling gas production from the naturally fractured Devonian shale Antrim formation in Montmorency Co., Michigan. The presence of multiple intersecting sets of natural fractures is the primary control on well deliverability and the Antrim must be fracture stimulated to be economical. However, due to the shallow depths (500- 2000 ft) and naturally fractured nature of the Antrim, fracture geometry is complex, and the determination of the optimal fracture treatment or completion methodology is not straightforward. To evaluate the effectiveness of fracture treatments in the Antrim, Shell conducted pressure transient modeling, microseismic tomography surveys for imaging created fracture dimensions (length, height, and dip), and the cutting of multiple coreholes to core the created hydraulic fractures. The integrated results suggest that fracture growth in the Antrim is very complex. A series of sub-vertical fractures were created that were parallel to the maximum principle stress and defined a zone of fracturing at least 50 feet wide. The fractures grew asymmetrically in height above the top perforation and appeared to follow a tortuous path along joint-set directions. Two coreholes drilled at 35-degree angles from vertical encountered 8 propped hydraulic fractures. Several of the cored propped fractures had varying azimuths suggesting that pre-existing natural fractures, which trend primarily NE/SW and NW/SE, were propped during the fracture treatment. P. 177
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