This work presents the results of tests using a low permeability (1.3 mD), medium porosity (34%) siliceous shale reservoir core sample initially saturated with oil followed by CO2 injection at miscible conditions. The tests had 3 primary flow conditions that replicate aspects of expected field conditions: (i) countercurrent exchange of carbon dioxide from fracture to matrix with consequent production of oil (ii) cocurrent exchange of carbon dioxide from fracture to matrix with oil production at the downstream core face, and (iii) a flushing stage where carbon dioxide is injected at a pressure drop of 25 to 50 psi to drive the core to residual saturation. The countercurrent and cocurrent conditions are conducted at very low pressure difference across the fracture at the face of the core and along the length of the core, respectively. The miscible injection of CO2 recovered virtually all of the original oil in place. Results were simulated with a compositional reservoir simulator. The simulation model was constructed to be as similar as possible to the experimental conditions, including a heterogeneous permeability field. An exact match of the experimental results was difficult to obtain. Calculations agreed with the experiments on the total oil production but not the timing of recovery. Experimentally, more oil was recovered during countercurrent flow in comparison to simulation. Nevertheless, simulations did reveal CO2 penetration of the matrix via a countercurrent diffusion/dispersion mechanism. Incorporation of fracture-to-matrix CO2 transfer and matrix-to-fracture oil transfer were key elements of the simulation.
Enhanced oil recovery from fractured low permeability reservoir rock is challenging and while studied previously, significant challenges remain in improving the recovery factor. In many cases the reservoir has been pressure depleted and gas released from solution. In such cases, continuous gas pathways from fracture to the matrix may have been created aiding our ability to deliver gas to the matrix. Gas injection (i.e., CO2) then proceeds from immiscible to perhaps miscible conditions. The efficiency of gas transport to the low permeability matrix is limited by the presence of a gas phase in the matrix, injection pressure, and cocurrent or countercurrent flow conditions, among others. This work presents the results of a series of experiments using low permeability (0.02 - 1.3 mD), medium porosity (30 - 40 %) siliceous shale reservoir core samples initially saturated with either: live oil, depleted to a pressure of 200–300 psi; or dead oil brought to near miscible conditions; followed by CO2 injection at pressures proceeding from immiscible to CO2 near miscible conditions. Two gas injection modes were used: CO2 flow across one face of the core (countercurrent flow) which intends to account for the diffusive transfer mechanism; and CO2 flow along the length of the core (cocurrent injection). The experimental setup was monitored using X-ray computed tomography that helped to visualize phase flow and distribution during the processes. The incremental oil recovery caused by the immiscible CO2 injection ranged from 0–10% for countercurrent flow mode and from 18–25% for cocurrent flow mode, whereas for near miscible conditions the recovery was found to be 25% for the countercurrent flow mode and 10% for the cocurrent flow mode. Countercurrent recovery appears to be critically sensitive to the distribution of the gas phase near the fracture face. Oil recovery potential by CO2 injection into siliceous shale rock is challenged by low permeability, rock heterogeneities, distribution of oil within the rock matrix, but it is aided by the presence of continuous gas pathways that allow CO2 penetration into the matrix. Near miscible injection displays clear multiple contact miscibility; also countercurrent flow seems to exhibit a greater recovery under near miscible as compared to immiscible conditions. Introduction Improving oil production from low permeability resources is strategically important. For instance, it is estimated that about one half of the worldwide petroleum resource is found in fractured siliceous and carbonaceous formations, yet fractured resources make up only roughly 20% of reserves (Saidi, 1983). As a greater number of reservoirs have matured and are reaching abandonment, recovery options are needed for more difficult to produce hydrocarbon settings. Examples of sizeable low permeability hydrocarbon resources include the Monterey Shale (CA, USA), West Texas Carbonates, the North Sea Chalks, and the Asmari Limestone (Iran). This paper is mainly concerned with enhancing recovery from the various units of the Monterey Formation that are biosiliceous and marine in origin, but we believe our work to be relevant to gas injection in the other rock types. In the San Joaquin Valley (CA), the uppermost productive member of the Monterey is the so-called Diatomite and includes fields such as South Belridge and Lost Hills. As depth increases, the rock has undergone diagenesis and transitions from amorphous to semi-crystalline opal. Beneath the Diatomite lie various siliceous shales such as the Brown and Antelope. Generally, metamorphism due to burial of diatomaceous oozes has led to first to opaline cristobalitic chert and porcelanite and with greater depth and time to quartzitic chert and porcelanite (Bramlette, 1946; Murata and Nakata, 1974). Burial diagenesis leads to loss of porosity and permeability, but to rock phases with greater thermodynamic stability.
Gas-and liquid-rich shales exhibit structural and compositional features across a broad range of length scales from meters to nanometers. This laboratory characterization effort of a shale sample aids hydrocarbon resource and reserves estimation, and improves understanding of flow behavior including potential geological carbon dioxide storage. Multiscale laboratory-imaging techniques were applied to characterize pore and microfracture structure of a Barnett Shale sample including connectivity and heterogeneity. X-ray computed tomography (CT) illuminated the krypton (Kr)-accessible porosity of centimeter-sized shale cores. Transmission X-ray microscopy (TXM) imaged micrometer-sized shale samples, and high-resolution scanning electron microscopy (SEM) revealed pore, fracture, and textural features. Registration of 190 lm resolution CT images with micrometer to nanometer resolution TXM and SEM images improved physical understanding of transport through organic-rich shale. Results focus on calcite-filled fractures and the calcite/shale-matrix interface as well as the distribution of micrometer-and nanometer-scale porosity. Fractures are likely both natural and induced. For the sample studied, pore accessibility determined by CT imaging corresponds with open microfractures that cross calcite-filled fractures and adjacent shale matrix. Such observations are made with corresponding micrometer-to nanometer-scale SEM images as well as compositional data. Taken together, these data indicate that calcite-filled fractures in this core act as a barrier to flow parallel to bedding except where breached by numerous open fractures. In contrast, these filled fractures enhance vertical flow, that is, flow between laminations. A region containing porosity and organic matter (with dimensions of tens to hundreds of nanometers) determined by 3D nanocharacterization with TXM and focused ion beam/SEM at the filled-fracture/shale-matrix interface facilitates this observed gas transport along the wall of the fracture fill. Areas adjacent to calcite-filled fractures and carbonaceous laminations within the shale matrix of the study sample are most readily accessed by Kr and may therefore be more readily produced than comparatively clay-rich laminations. The numerous open fractures and sheet pores within the calcite fracture fill, as well as the inherent weakness of the porosity and organic matter at the fracture-fill/shale-matrix interface, are indicative of its susceptibility to reopening and fracturing.
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