Journal of Unconventional Oil and Gas Resources最新文献

With increasing interests and demand in natural gas, it is important to understand and predict the flow processes in unconventional tight- and shale-gas reservoirs. Because the permeability is very low and the pore throat size is very small in tight- and shale gas reservoirs, gas flow mechanisms are different from that in conventional reservoirs. Slip flow, for example, often happens. Generally, apparent permeability is used to correct flow deviation from conventional flow. In this paper, apparent permeability is distinguished for different components in the reservoir, and incorporated into a compositional model to study the effect of distinguishing apparent permeability on the BHP (Bottom Hole Pressure) and gas composition. Several comparison simulation scenarios are performed to show the significance of distinguishing permeability for different gas components. The results show output predicted without distinguishing apparent permeability for gas components make larger deviation at higher production rate, lower permeability and more content of heavier component, and the interpretation by this method can under estimate formation permeability by 14%. Therefore, distinguishing the apparent permeability for different components is very important and would lead to more accurate results of BHP and gas composition which are very important factors for gas recovery.

The fracture-permeability behavior of Utica shale, an important play for shale gas and oil, was investigated using a triaxial coreflood device and X-ray tomography in combination with finite-discrete element modeling (FDEM). Fractures were generated in both compression and in a direct-shear configuration that allowed permeability to be measured across the faces of cylindrical core. Shale with bedding planes perpendicular to direct-shear loading developed complex fracture networks and peak permeability of 30 mD that fell to 5 mD under hydrostatic conditions. Shale with bedding planes parallel to shear loading developed simple fractures with peak permeability as high as 900 mD. In addition to the large anisotropy in fracture permeability, the amount of deformation required to initiate fractures was greater for perpendicular layering (about 1% versus 0.4%), and in both cases activation of existing fractures are more likely sources of permeability in shale gas plays or damaged caprock in CO₂ sequestration because of the significant deformation required to form new fracture networks. FDEM numerical simulations were able to replicate the main features of the fracturing processes while showing the importance of fluid penetration into fractures as well as layering in determining fracture patterns.

Understanding adsorption behavior of methane in shale is important for predicting the gas reserve and evaluating reservoir potential. This paper presents the methane adsorption behavior of three gas shale samples of Gondwana and KG basin of India. Adsorption experiments are conducted on as-received samples at a temperature of 40 °C to a maximum equilibrium pressure of approximately 9.5 MPa. The methane adsorption data are applied to test the applicability of Langmuir isotherm model. It was observed that the experimental adsorption data for Parbatpur and KG shale samples did not follow the Langmuir isotherm model, with deviation from the model value more than 10%. Although the experimental adsorption data of Salanpur sample broadly followed the Langmuir model, the deviation from the model value was more than 5%, implying the Langmuir model is not very accurate. Pore characterization study was also carried out to understand the pore structure of the shale samples. The pore characterization suggested that porosity of Indian gas shales are dominated by meso- and macro-pores.

Tracer test is a useful method to investigate various phenomena in geological porous media including groundwater contaminant transport, sweep efficiency and retention time in oil reservoir, reservoir characterization, fractures orientation assessment, as well as geothermal reservoir evaluation. Numerical methods are powerful tools in interpreting tracer test results. However, they are limited by computational restrictions which include finer grid requirements and small calculation steps. In this study, an analog model of a quarter five-spot porous reservoir was simulated by using random walk particle tracking method. This scheme used ‘method of images’ with pairs of injector–producer potential flow to generate the velocity vectors instead of conventionally solving Darcy’s equation to obtain grid velocities. Simulated breakthrough concentration profiles and flow visualization were compared with both experimental results and Eulerian-grid based finite volume simulation. The predicted breakthrough curves of tracer concentration were found to agree with experimental data sets. In addition to be free from numerical errors as often encountered in grid-based simulation, the proposed particle tracking model showed a faster computational time. Unlike the conventional grid method, this technique provides inherently smooth and continuous flow field at arbitrary position within the reservoir model.

The Mississippian Barnett shale of the Fort Worth Basin is one of the most successfully developed shale gas plays in North America by applying multistage hydraulic fracturing stimulation techniques. The fracturing design involves pumping low viscosity fluid with low proppant concentrations at high pump rate, commonly known as “slick water fracturing”. Direct laboratory measurement of natural and induced fracture conductivity under realistic conditions is needed for reliable well performance analysis and fracturing design optimization.

During the course of this study a series of conductivity experiments was completed. The cementing material present on the surface of natural fractures was preserved during the initial unpropped conductivity tests. The induced fractures were artificially created by breaking the shale rock along the bedding plane to account for the effect of irregular fracture surfaces on conductivity. Proppants of various sizes were manually placed between rough fracture surfaces at realistic concentrations. The two sides of the induced fractures were cut in a way to represent either an aligned or a displaced fracture face with a 0.1 inch offset. The effect of proppant partial monolayer was also studied by placing proppants at ultra-low concentrations.

Results from the experiments show that unpropped induced fractures can provide a conductive path after removal of free particles and debris generated when cracking the rock. Poorly cemented natural fractures are effective flow paths. Unpropped fracture conductivity depends strongly on the degree of shear displacement, the presence of shale flakes and particles, and the amount of cementing material removed. The propped fracture conductivity is weakly dependent on fracture surface roughness at higher proppant concentrations. Moreover, propped fracture conductivity increases with larger proppant size and higher concentration in the testing range of this study. Results also show that proppant partial monolayers cannot survive higher closure stresses.

The long-term storage of carbon dioxide (CO₂) via injection into deep geologic formations represents a promising technological pathway to reducing greenhouse gas emissions to the atmosphere. Geologic storage in deep saline aquifers has been studied extensively, and the injection of CO₂ for enhanced oil recovery (EOR) from conventional (porous and permeable) formations has been practiced for decades. This study is focused on developing a preliminary assessment of the economic feasibility of storing CO₂ in depleted unconventional natural gas-bearing shale formations. Using a surrogate reservoir model (SRM) and a flexible environment for techno-economic analysis, this paper presents site-scale estimates of long-term CO₂ sequestration costs in depleted shale gas formations and discussion of the likely major cost drivers. This analysis focuses on the transportation of CO₂ from industrial point sources in the Pennsylvania Marcellus Shale region, and the transition of Marcellus wells from production to CO₂ injection. This approach couples techno-economic analysis with reservoir simulation models to estimate costs associated with transportation, injection, CO₂ separation and post-injection monitoring of CO₂ storage permanence from large industrial point sources in depleted shale-gas reservoirs. We also consider potential revenue from incremental CH₄ recovery (effectively enhanced gas recovery) in reservoir scenarios where such production is significant. The techno-economic model boundary includes pipeline transport from an industrial source (excludes the cost of capture of CO₂ at that source), site preparation and CO₂ flooding operations, and long-term monitoring and post-injection site care (PISC) at the storage site. Under an operational scenario where a Marcellus shale gas well is in primary production for 42 years prior to the initiation of CO₂ injection, it is estimated that CO₂ could be transported and stored at a levelized cost of $40–$80 per metric tonne, in present value terms. These costs are shown to be highly sensitive to assumptions regarding well spacing, bottomhole pressure, CO₂ transport distance and the future price of natural gas. In most of the scenarios considered, transportation and injection costs were dominant factors, while CO₂ separation, pore space acquisition and post-injection site care/monitoring did not significantly influence levelized costs.

The Bakken shale and similar formations in North Dakota are a new, poorly characterized resource and the oil production potential of North Dakota is highly uncertain. To better understand this resource, we employ a least squares curve fitting method on 5773 wells in the Bakken, drilled from 2005 to mid-2013, fitting each well with hyperbolic decline (HD) and stretched exponential (SE) decline models. We characterize well productivity by vintage and location. Additionally, we construct scenarios to simulate future production by varying individual well productivity, well spacing, and drilling rate. Using the HD model, a typical Bakken well drilled to date is expected to produce 270 mbbl (mean) or 221 mbbl (median) over a 15-year life. Using the SE model these figures are slightly lower: 231 mbbl (mean), 181 mbbl (median). Over our study period, the cumulative production in the first six months of a well’s life (IP180) increased and then remained steady. EURs increased until 2010 and have decreased since 2010. It appears that wells are becoming less productive over time, with the reasons not yet fully accounted for. Our base forecast has North Dakota producing at least 1 mmbbl/day for over 20 years, peaking at approximately 1.7 mmbbl/day in the mid-2020s. This period of high production can be shortened by faster-than-expected decline or extended by advances in technology.

Advances in horizontal drilling coupled with hydraulic fracturing have unlocked trillions of cubic feet (billions of cubic meters) of natural gas and billions of barrels (millions of cubic meters) of petroleum in shale plays across the United States. There are over 72,000 unconventional well sites in the United States, with anywhere from 2 to 13 million gallons (7500–49,000 cubic meters) of water used per unconventional well. While unconventional wells produce approximately 35% less waste water per unit of gas than conventional wells, the sheer number of wells and amount of oil and gas being produced means that water use has increased by as much as 500% in some areas. Such large water demands give rise to questions about water management, including acquisition, transportation, storage, treatment, and disposal. While these issues vary by play, some key concerns include competition for drinking water sources, impacts of fresh and wastewater transportation, the extent of wastewater recycling, contamination, and the effects of various treatment and disposal methods on communities and watersheds. These concerns have not been fully resolved, yet there is a noticeable, and largely quantifiable, evolution of management practices toward operating more sustainably and with smaller regional impacts. Here we explore water management issues as they arise throughout the unconventional drilling process, particularly focusing on how practices have changed since the beginning of the shale boom and how these issues vary by play.

Determination of petro-physical properties of coal bed methane (CBM) reservoirs is essential in evaluating a potential prospect for commercial exploitation. In particular, permeability of coal and relative permeability of coal to gas and water directly impact the amount of hydrocarbons that can be ultimately recovered. Due to the complex and heterogeneous nature of coal seams, proper relative permeability relationships are needed to accurately describe the transport characteristics of coal for reservoir modeling and production forecasting. In this work, absolute and relative permeability of different coal samples were determined experimentally under steady-state flowing conditions. Multiphase flow tests were conducted using brine, helium and carbon dioxide as the flowing phases under different magnitudes of confining and pore pressures. Results indicate that effective stress (confining pressure – average pore pressure) has a significant effect on both absolute and relative permeability of coal. With increases in effective stresses, the absolute permeability decreases. Effective permeability and relative permeability, as well as the cross over point and the width of the mobile two-phase region decrease as the effective stress increases. In addition, the mobile range of gas and water in the coal samples investigated corresponds with water saturations above 50%, irrespective of the base absolute permeability of the sample. In brine–carbon dioxide two-phase flow experiments, the effect of carbon dioxide adsorption was observed as effective permeabilities decreased in comparison to the helium–brine permeabilities at the same flowing ratios. As a result, relative permeability characteristics of CBM systems were found to be insufficiently represented as sole functions of fluid saturation. Field scale simulations of primary recovery from CBM systems using variable, stress-dependent relative permeabilities, showed a significant decrease in cumulative gas recovered. A multi-dimensional correlation between relative permeability, fluid saturation and specific surface area of the cleat network is proposed as a continuation from this work in order to account for stress-related changes in cleat network connectivity.