Pinnacle Technology

Abstract A novel, cost-saving approach combining advanced electronic and chemical technologies for rapidly acquired reservoir flow measurements and early-alteration of flows is described. The combined technologies improve CO2 injection, leak detection, and reservoir flow management in offshore CO2 enhanced oil recovery (EOR) and carbon capture and storage (CCS) projects. The approach is based on old and new technologies that have been field-proven in land-based operations. It employs reservoir flow-induced micro-deformation measurements by tiltmeters and absolute seafloor position monitoring using global positioning systems combined with underwater acoustic distance measurements from the sea surface to instruments installed in the seafloor over offshore reservoirs. These systems can acquire micro-deformation data, which allows for geomechanical inversion analysis to provide 3-D reservoir flow images. Real-time temperature, pressure, and other data from fiber-optic sensors may also be needed to better characterize some CO2 flows. New flow-controlling and leak-sealing chemical systems and placement methods combined with conventional ones have improved the options for management of flow paths both inside and outside of offshore reservoirs. The paper includes a discussion on how the monitoring technology has evolved from similar methods proven in EOR projects, and more recently in CCS projects, to identify reservoir flows and pinpoint abnormal ones. An example of normal CO2 flow results is presented to show how operators can calibrate flow-prediction software models and make fast decisions to apply flow enhancing methods that improve CO2 sweep efficiency, increase oil production, and better utilize reservoirs' CO2 storage capacity. Another example shows the early identification of an abnormal-flow path location that enables operators to make timely selections of sealing methods and materials to eliminate unwanted flows inside or outside of reservoirs and ensure planned CO2 plume movement and containment within reservoirs. The CO2 flow controlling and remediation technology's history of field proven success is described along with the recently developed versions. Generic case histories of conventional methods on land vs. the proposed offshore systems are compared to show how the new approach creates synergy that can improve the performance of offshore CO2 EOR and CCS projects while reducing operating costs.

Abstract Mapping the microseismic activity during a hydraulic treatment is widely used to determine the geometry of the stimulated fracture network. Microseismic maps provide reliable information on the development of fracture symmetry, half-length, azimuth, width and height, and their dependence on the treatment parameters and reservoir characteristics. Beyond that, these fracture geometries are used to better understand fracture modeling and even production characteristics. Fiber-optic-based distributed temperature sensing (DTS) arrays provide almost immediate updates of the near-wellbore temperature distribution in approximately one-meter intervals. In injection treatments, the near-wellbore temperature distribution can be used to determine isolation effectiveness, the relative amount of fluid each perforation cluster takes, fracture initiation points, and effective fluid diversion. In production analysis, DTS measurements can quantify production rates from each perforation interval, crossflow rates while shut-in, and fluid types recovered from each perforation interval. The detailed near-wellbore results available through DTS coupled with the far-field geometry acquired through microseismic mapping provide an accurate picture of the completion effectiveness. Microseismic mapping results often show adequate resolution over a large area but lack the fine resolution that would allow it to identify near-wellbore effects in the meter range. When modeling and interpreting the treatment geometry obtained by the microseismic-event distribution, it is important to include the correct near-wellbore effects, which are readily accessible through DTS measurements. Combining the two diagnostic tools is valuable for real-time decision making, post-treatment analysis, and production analysis to assess the completion effectiveness. Incorrect assumptions about perforation breakdown, fracture-initiation points, interval isolation, or limited-entry effectiveness can lead to misinterpretations of the microseismic results. Using both diagnostic tools provides firm answers to the overall completion effectiveness. This paper focuses on three distinct aspects of combining the analysis of microseismic mapping and DTS. The first is the real-time aspect, wherein real-time decisions and adjustments are made during the fracture treatment with the objective of manipulating the results towards the desired outcome. The second is using both tools to perform more accurate postfracture analysis, including calibrated fracture modeling, entry effectiveness, correct interval spacing, and stimulated reservoir volume (SRV) analysis. The third area covered is combining these diagnostic tools with a production analysis, which is acquired through analysis of the temperature data.

Abstract Microseismic fracture mapping has provided significant insights into the nature of fracture growth in unconventional gas reservoirs (primarily shale) and allowed detailed characterization of the created network size and to a lesser extent the internal network structure (i.e., fracture spacings, azimuths, and degree of complexity). Fracture mapping has shown that large volume slickwater stimulations can access millions of square feet of reservoir area. In most unconventional gas reservoirs, well performance is directly related to the size and complexity of the fracture network; however, well performance is also affected by un-propped and propped fracture conductivity and proppant distribution within the fracture network. This paper examines the relationship between network size, proppant distribution, and well performance. A series of reservoir simulations were used to quantify the effect of network fracture conductivity and proppant distribution on well performance. The simulations evaluate a range of reservoir permeability from 0.0001 to 0.01 mD and utilize a network size and fracture spacing that is consistent with microseismic mapping measurements. Proppant transport cannot be reliably modeled in complex fracture networks, but it is likely that much of the fracture network is un-propped (Cipolla et al.2008). Un-propped fracture conductivities of 0.5 to 5 mD-ft were evaluated in this study. This work investigates the effect of proppant transport from a primary fracture into a fracture network and proppant banking in the primary fracture on well productivity. The results of the reservoir simulations illustrate the likely impact of stimulation designs on well performance. The results from this work provide a better understanding of fracture conductivity requirements in unconventional gas reservoirs that can be used to improve stimulation designs through improved proppant selection and scheduling. The results of the reservoir modeling show that proppant transport, even short distances, into the fracture network can have a significant affect on well productivity in cases where un-propped fracture conductivity is not adequate to fully exploit fracture complexity. In addition, proppant banking is likely with the low viscosity fluids used in many fracture treatments in unconventional gas reservoirs, which will result in the formation of a high conductivity arch at the top of the proppant bank. The impact of this high conductivity arch can be significant and affect treatment designs, many times reducing proppant volumes and conductivity requirements.

Summary Natural and induced fractures provide the only means of production in tight gas sand reservoirs. The objective of this work is to locate and characterize natural and induced fractures from the analysis of scattered waves recorded on 4-D (time lapse) VSP data in order to optimize well placement and well spacing in these gas reservoirs. Using synthetic seismic data, we have previously shown that it is possible to characterize the quality of fracturing based upon the amount of scattering of seismic energy from hydraulic fractures. We show this concept applied to a field dataset from the Jonah Field in Wyoming. The time lapse (4D) VSP data from this field are imaged with a migration algorithm using shot travel time tables derived from the first breaks of the 3D VSPs and receiver travel time tables based on the microseismic and perf shot arrival times. We create images of the fracture planes through two of the hydraulically fractured wells in the field. The scattered energy shows correlation with the locations of the microseismic events and azimuthal scattering which is different from the azimuthal reflectivity of the reservoir. This gives us more confidence that we have separated the scattered signal from simple formation reflectivity. Variation of the scattered energy along the image planes suggest differences in the quality of the fractures in three distinct zones.

Abstract The oil reservoirs in the Changqing Oilfield consist of stacked sand/shale deposits, and the majority of the target zones have a permeability of 0.05–0.3mD. All oil wells completed in tight reservoirs from the Changqing Oilfield require fracture stimulation to achieve commercial production and to improve well productivity. Fracture stimulation is also very common for water injection wells to enhance injectivity. Multiple payzones in the region were either stimulated with standalone treatments that were isolated and pumped separately or with single-stage treatments to simultaneously treat several intervals using a kind of limited-entry technique. However, with the continuing development in these fields, larger pay intervals (gross pay thickness up to 75 meters) with poorer reservoir quality were encountered. Post-fracture production results indicated that the above stimulation techniques were not always effective in these tight reservoirs. As a result, a new staging technique was evolved and employed to stimulate these tighter reservoirs with better economic effectiveness. With this technique, two or three pay intervals were first perforated and dual-stage fracture treatments were then performed: one stage at a time without using any mechanical isolation. The idea was two-fold:using the stress increase around the fracture created by the first injection to divert the subsequent treatment to un-stimulated interval(s), andusing the proppant banks created from the first propped treatment to minimize the proppant settling to the bottom portion of the fracture created by the second propped treatment. Three-month average post-treatment production data indicated that the dual-stage treatments outperformed conventional single-stage treatments in some reservoir environments. Candidate selection was a key to the success of this technique, and reservoir conditions that favor these types of treatments are as follows: multiple pays, lower permeability, lower net pressure, and less stress contrast between different payzones. Radioactive tracer logging and microseismic fracture mapping were conducted to evaluate fracture height growth. This paper presents a case history of fracture performance evaluations. Reservoir data, fracture modeling and post-fracture production data were compiled and employed to demonstrate the benefits of this fracture treatment technique in some tight oil reservoirs.

Abstract We have modeled the warm-up phase of a SAGD project using a coupled reservoir simulator and stress model. We matched the injection pressure by adjusting the reservoir permeability. A fair match between data and model was obtained. Micro-seismic monitoring indicated localized injection at the toe, which was used in the model. Also, the seismic signature indicated strike slip and possibly overthrust fault slippage or casing failure as cause of the seismicity. This confirms the reservoir and stress model used in the interpretation. While most of the steam was injected at the toe, the uplift was largest at the heel of the well. This can be best explained by reservoir heterogeneity, which implies that surface heave measured with tiltmeters can best be interpreted using a geomechanical model. The matched coupled model can be used for optimizing the completion and injection process.

Abstract Tight gas fracturing was pioneered in North America in the 1970's and 1980's, and also has a relatively long history in Germany. In the rest of the world, however, massive fracturing for production from tight gas formations (i.e. k < 0.1 mD) has been very rare, due mainly to poor economics, rather than lack of opportunities. A massive oil field was recently discovered in Rajasthan (northwest India). The field development would require significant amounts of natural gas for heating and processing of the waxy oil to be produced. The most economical solution to provide sufficient gas in this remote desert location was to produce it from a deeper formation discovered in the same area. The majority of the gas is contained in a volcanic section of basalts and felsics. A fracturing campaign was performed in 2006 on three deep gas wells to evaluate the post-stimulation production increase from a number of different horizons, with base formation permeabilities varying from 0.005 to 0.15 mD. A comprehensive program of core testing, fluids compatibility testing and pre-fracture diagnostic injections was performed. Fracture stimulation treatments were performed in three different sections of this very thick gas-bearing formation (> 400 m gross height). The formations ranged from the highest permeability (0.15 mD) Fatehgarh sandstones, to a lower permeability Felsic section (0.05 mD) and the lowest permeability volcanic rock (0.005 mD). All three types of rock were stimulated successfully and post-fracture well testing showed initial production rates agreeing with what was expected based on reservoir simulation. This important result supports the proposition that unconventional gas resources in Asian countries can be attractive when stimulation techniques perfected in other areas (i.e. North America) are applied1.

Abstract Most existing production of waxy oils occurs from high permeability formations, and wax issues are mostly a problem in the production tubing or pipeline. Large reserves do also exist in low permeability formations that require hydraulic fracturing for economic production. Such a reservoir was recently discovered in Rajasthan (northwest India), overlying a more typical high permeability formation, both with high pour point waxy oil. Since a very large amount of oil-in-place is present in the low permeability formation, two fracturing campaigns were performed in two different horizons to assess the potential for successful well stimulation. The first fracturing campaign (on four wells) showed limited success. A study was performed to determine the reason for the failure, and significant changes were made for the 2nd campaign. This paper documents the 2nd campaign. This campaign featured the first successful use of heated fluids in India to stimulate a shallow, low permeability, massive oil reservoir containing high pour point waxy oil.