Modern advancements in technologies pertaining to the drilling of horizontal well and multi stage hydraulic fracturing have made it possible to get significant hydrocarbon production even from extreme low permeability formations. However, correct evaluation of the economics of the project is becoming increasingly essential before committing to any big investment. In this scenario, production forecasting based on reservoir simulation plays an important role by not only evaluating the economic feasibility of the project, but also helping in the selection of the most optimal development strategy. In this paper, a workflow has been demonstrated that proved useful in addressing such challenges related to the tight reservoirs (permeability less than ~2mD). The methodology adopted in this study can be divided into two parts. The first part involves data preparation for single well numerical modeling similar to Daungkaew et al (2008) and Kumar et al (2008). This includes building a petrophysical model based on the mineralogy characterization and also carrying out Rate Transient Analysis (RTA) for permeability estimation using the data acquired from an existing well (Pan et al, 2011). RTA is preferred over the conventional buildup analysis as it does not require shutting of the well. The second part of the workflow involves creation of a numerical model based on the petrophysical, PVT and SCAL data. Hydraulic fracture (if present) is modeled by editing the permeability of the grid cells falling under the fracture geometry. The model is calibrated with the production data after initializing with the pressure and fluid contacts. The history matched model is then used to generate production forecasts of multiple scenarios including horizontal well with multiple stages of fracturing and sensitivities can be made with respect to drainhole length, fracture stages etc. Furthermore, economic analysis can be carried out to select the most economically viable case. The proposed workflow has been applied in one of the low permeability oil field in India. The permeability derived from RTA was in close agreement with the core results. This workflow was used to generate production forecasts for multiple development scenarios. It was used to optimize the number of fracture stages, keeping the drainhole length constant. In this paper, a novel approach is discussed that combines the RTA and single well numerical modeling technique to evaluate different strategies of producing from a tight reservoir. Based on the economic analysis then, one can maximize the return.

Unconventional resources, which are typically characterized by poor porosity and permeability are being economically developed only after the introduction of hydraulic fracturing (HF) technology, which is required to stimulate the hydrocarbon flow from these impermeable/tight reservoir rocks. Since 1960, HF has been extensively used in the industry. HF is the process of (1) injecting viscous gel fluids through the wellbore into the subterranean hydrocarbon formation, at high pressures sufficient enough to exceed tensile strength of the rock and hydraulically induce cracks/fractures (2) followed by injecting proppant-laden fluid into the open fractures and packing up the fracture with proppant pack, after the injected fluid leaks off into formation. The resultant proppant pack keeps the induced fracture propped open and thus creates a highly conductive flow path for the hydrocarbon to flow from the far-field subterranean formation into the wellbore. Most the modern wells in unconventional reservoirs are horizontal/near-horizontal wells that are completed with large multiple HF treatments across the entire length of the horizontal wellbore (lateral), to increase the reservoir contact per well. Productivity of these wells is dictated by the stimulated reservoir volume (SRV), which is dependent on the number of fractures and conductive hydraulic fracture surface area of each fracture that is propped open. Therefore, estimation of the hydraulic fracture geometry (HFG) dimensions has become very critical for any unconventional field development. Key dimensions are hydraulic fracture length, height, and orientation, which are required to assess the optimum configuration of fracturing, well completion, and reservoir management strategy to achieve maximum production. Designs can be assessed based on HFG observations, and infill well trajectories, spacing, etc. can be planned for further field development. This workflow proposes a method to estimate and model all or at least two parameters of HFG in predominantly horizontal or nearly horizontal wells by use of interwell electromagnetic recordings. The foundation of this workflow is the difference in salinity, or more precisely resistivity, of the fracturing fluid and the resident fluid (hydrocarbon or formation water). The fracturing fluid is usually significantly less resistive than the hydrocarbon that is the dominant resident fluid where fracturing is usually conducted, or less resistive than the formation water in case the HF occurs in high water saturation regions. Therefore, the resistivity contrast between the two fluids will demarcate the boundary of hydraulic fractures and thus help in precisely modeling some or all parameters of HFG. The interwell recordings can be interpreted along a 2D plane between the two wells, one of them bearing the transmitter and the other with the receiver. The interpretations along a 2D plane can be used to calibrate a 3D unstructured HF model, thereby introducing a reliable calibration input that did not exist before. There can be multiple such 2D planes as more than one well can have a receiver, and, in that case, the 3D HF model has more calibration data and is even more precise. The reason this workflow significantly improves precision in HFG estimation and modeling is that it provides the ability to demarcate only the open portion of the HF and not the entire volume where pumping fluid entered, which would include parts that closed too quickly to contribute to the production from the well. Today, the industry, by its best methods, can only see the entire rock volume that broke due to fracturing, although significant parts of that broken volume might not be contributing to the production and thus are irrelevant in the 3D models upon which important decisions such as production forecast and project economics are based.

Whereas the application of EOR methods is estimated to recover nearly 6 out of the 9 trillion barrels initially in-place globally, there is a high chance of failure of an EOR project due to lack of characterization, operational challenges, misplaced concept, etc. It is extremely challenging to reduce these uncertainties and hence the success of an EOR project is a big question, except for the case in which the method is relatively immune to such uncertainties. The gas-assisted gravity drainage (GAGD) technique is an excellent example of such a method where the recovery is enhanced by concepts of gravity and fluids' density differences and thus relatively safer from execution failures. It has been proposed as a viable alternative to, and improvement over, conventional gas injection techniques such as water-alternating-gas (WAG) and continuous gas injection (CGI), because of its higher chance of success. The success of GAGD hinges very strongly on the interplay between in-situ reservoir properties (rock and fluid parameters) and the range of operating parameters imposed. In the primary GAGD configuration, gas is injected in the crest, and oil is withdrawn (produced) via a horizontal well at the bottom of the structure. In this study, a simplified black-oil numerical simulation framework has been developed to assess the viability of the GAGD process in candidate reservoirs with focus around lower permeability reservoirs coupled with hydraulically fractured rocks. Incremental production over natural depletion and hydraulic fractured cases have been used as the assessment criterion.

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