Carbon dioxide (CO2) flooding is an EOR technique in which carbon dioxide is injected into the reservoir to improve the oil recovery. The reservoir oil and rock properties are altered when carbon dioxide interacts with the oil and rock present in the reservoir. Carbon dioxide injection alters the oil and rock properties by causing reduction in oil viscosity, oil swelling and wettability alteration of the rock. This paper will present a proposal to study the wettability alteration in carbonate formations during miscible carbon dioxide flooding. In miscible carbon dioxide flooding, the injection pressure of carbon dioxide would be kept above the minimum miscibility pressure. Thus carbon dioxide is miscible with the oil present in the reservoir. This paper primarily focuses on understanding the effect of crude oil composition on the change in wettability and asphaltene precipitation in carbonate rocks during miscible carbon dioxide flooding. Experiments will be carried out with different crude oils (Heavy, Medium and Light) on the same carbonate rock, at reservoir conditions, in order to observe the change in rock wettability. Interaction between formation and asphaltene would be investigated by measuring precipitation quantitiy into production recovery and rock at constant CO2 reservoir pressure. Carbonate rocks are very special due to the fact that usually carbonate rocks are oil wet and carbon dioxide tends to change the wettability of the carbonate rocks from oil wet to water wet. This change in wettability of the reservoir rock increases the oil recovery. Literature review revealed that considerable amount of research has not been done on the wettability alteration of carbonate rocks during miscible CO2 flooding process. Thus this topic needs to be further investigated and studied.
CO2 injection is considered as one of the successful methods used for enhanced oil recovery (EOR) in oil fields to recover residual oil. It increases mobility and reduces viscosity and interfacial tension. Asphaltene precipitation and deposition phenomena appear in petroleum reservoirs due to change in temperature, pressure, and liquid phase compositions; either during the primary production or enhanced oil recovery processes. Asphaltene precipitation might occur due to CO2 injection in light oil (>30° API) reservoirs which may cause blockage of production system, decrease in permeability, wellbore plugging and change in porosity. Experimental data concludes high asphaltenes precipitation and lower asphaltene solubility in light oils. Hence severe damage to formation can happed sue to asphaltene precipitation, in some cases the loss might be irreversible. This paper furnishes the investigation of asphaltene precipitation caused by CO2 injection. In this regards interaction between asphaltene and formation, precipitation quantity under different injection flow rates of CO2 at the constant injection pressure have been investigated. Results conclude that there is direct proportionality between asphaltene precipitation and amount of injected gas in the core sample, whereas inverse proportionality between asphaltene precipitation and increased injection flow rate of the gas at constant injection pressure.
Formation permeability (k) and fracture half-length (Xf) determination provides the ability to economically optimize well and fracture spacing. For wellbores completed in the gas-condensate and oil window (producing below saturation pressure) two-phase flow occurs from the fracture face increasing in distance until it reaches the no flow boundary from the adjacent fracture face along a horizontal wellbore. Thereafter the flow becomes boundary dominated. It becomes challenging to precisely pick the end of linear flow time and the start of boundary dominated flow regime due to long transient region in shales (low permeability nature). End of linear flow time is used to calculate both the permeability and original gas in place (OGIP) using production data. Existing practices in the literature suggest to pick the end of linear flow time implicitly from the plot of reciprocal rate vs cumulative production. The deviation on the line is termed as typically the time at which linear flow has ended. However, considering the lengthy transition regions in shales, this involves a great deal of error as the end of linear flow time is not calculated mathematically but picked on the analyst's eyeballing practices. Thus, a small mispick of end of linear flow time could result in substantially misleading permeability and OGIP. The primary work presented in this paper resolves the selection of end of linear flow time by proposing a technique which involves production data analysis equations and statistical methods along with graphical techniques to calculate and rightly pick the end of linear flow time. Since gas condensate ratio (GCR) remains constant during the linear flow regime, our methodology also involves reverification of the end of linear flow time. This is done by picking the increase in GCR which happens at the end of linear flow on the plot of cumulative production versus the GCR. While the procedure involved laboratory fluids, special core analysis, and numerical simulation, the methodology lends to a wide range of liquid-rich reservoirs where linear flow analysis is appropriate.
Appraisal and development of tight gas discoveries in Pakistan is a longstanding yet unsettled challenge to local oil and gas E&P industry. Major challenges include but not limited to marginal gas in-place volumes, sustainability of production rates, lengthy cleanup period, significantly higher capital costs due to imported technologies and services, less volume of work, lower competition among the service providers, lower quality gas, lower recovery factors due to tightness and water production, complex reservoir geology and petrophyics. Several such technical discoveries are being made by local and multinational E&P companies time to time but due to one or the other mentioned challenges such discoveries are presumed to be non-commercial and left unexploited. This paper shares a case study of a real tight gas carbonate reservoir located in Middle Indus Basin of Pakistan which may help the E&P professionals’ kick-off the thought process to understand such discoveries and adopt new strategies to bring them on production. The well Naushahro Feroze X-1 (NF X-1) was drilled as an exploratory well to target Chiltan Carbonate Reservoir in the Naushahro Feroz block in Sindh, Pakistan. A tight gas discovery was made in the Chiltan formation based on the well logs and testing results. It was concluded as naturally fractured carbonate reservoir (NFR) and classified as Type-II NFR, Nelson (2001)1 i.e., mainly fractures provide essential flow capacity. Reservoir evaluation indicated reservoir is over pressured and its permeability is in micro Darcies. Subsequent horizontal appraisal well i.e., NF Hor-1(RE) drilled with a lateral section of ~1300 meters. The well was completed with an open-hole-multistage string and ten stages were selectively acid stimulated, acid fractured and hydraulically fractured to establish the sustainable commercial gas rates. The performance of both the exploration and appraisal wells exhibited typical production behavior of tight gas wells with continuous decline in gas rate and wellhead flowing pressures, however, the appraisal well proved to be better in terms of production due to better drilling, completion and stimulation strategy. Sustainable production rate in the appraisal well could not be established due to extremely tight nature of the matrix and water production from the deeper intervals. Surface separator multirate test was performed followed by an extended buildup period and the surface data was recorded. The data was then used to understand the reservoir behavior on short term and long-term basis using various analytical and numerical analysis techniques. A 3D Black Oil dual porosity model was developed for reservoir simulation and understanding the reservoir behavior. In the static model, the natural fractures were characterized using the seismic attributes across the Chiltan formation. The model was then initialized, and history matched using the available rock and fluid properties, multirate test and extended buildup data. After completing the analysis, an understanding was developed about the production strategies and well wise range of gas recoveries in such tight gas discoveries which has been shared in this paper.
It is normally understood in the industry that permeability and porosity are related but relationship can be strong or weak based on heterogeneity, anisotropy and lithology of the reservoir. So far linear models have been arbitrarily being tried to fit and matched with the data thereby resulting in a poor relationship. This paper seeks to explore data mining techniques for pattern recognition including Kohonen self-organizing maps and other unsupervised learning techniques. Kohonen self-organizing maps and principal component analysis are applied over permeability –porosity data to first cluster the data into various sets. This data can then be linked back to the formations and a predictor can be built thereby giving a tool for reservoir characterization. Then a linear model is to be built with the linearity being assessed by Shapiro Wilk Test and Quantile – Quantile (Q-Q) plot. This technique develops a relationship with a much better fit between permeability and porosity in respective ranges and thereby creating a higher cue-efficient of determination i.e. R squared value.
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