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Abstract Characterization of hydraulic fracture system in multi-fractured horizontal wells (MFHW) is one of the key steps in well spacing optimization of tight and shale reservoirs. Different methods have been proposed in the industry including core-through, micro-seismic, off-set pressure data monitoring during hydraulic fracturing, pressure depletion mapping, rate-transient analysis, pressure-transient analysis, and pressure interference test. Pressure interference test for a production and monitoring well pair includes flowing the production well at a stable rate while keeping the monitoring well shut-in and recording its pressure. In this study, the coupled flow of gas in hydraulic fractures and matrix systems during pressure interference test is modeled using an analytical method. The model is based on Laplace transform combined with pseudo-pressure and pseudo-time. The model is validated against numerical simulation to make sure the inter-well communication test is reasonably represented. Two key parameters were introduced and calculated with time using the analytical model including pressure drawdown ratio and pressure decline ratio. The model is applied to two field cases from Montney formation. In this case, two wells in the gas condensate region of Montney were selected for a pressure interference test. The monitoring well was equipped with downhole gauges. As the producing well was opened for production, the bottom-hole pressure of the monitoring well started declining at much lower rate than the production well. The pressure decline rate in the monitoring well eventually approached that of the producing well after days of production. This whole process was modeled using the analytical model of this study by adjusting the conductivity of the communicating fractures between the well pairs. This study provides a practical analytical tool for quantitative analysis of the interference test in MFHWs. This model can be integrated with other tools for improved characterization of hydraulic fracture systems in tight and shale reservoirs.
Azahree, Ahmad Ismail (PETRONAS Research Sdn. Bhd.) | Jaafar Azuddin, Farhana (PETRONAS Research Sdn. Bhd.) | Mohd Ali, Siti Syareena (PETRONAS Research Sdn. Bhd.) | Yakup, Muhammad Hamzi (PETRONAS Research Sdn. Bhd.) | Mustafa, Mohd Azlan (PETRONAS Research Sdn. Bhd.) | Widyanita, Ana (PETRONAS Research Sdn. Bhd.) | Kalita, Rintu (PETRONAS Center of Excellence)
Abstract A depleted gas field is selected as CO2 storage site for future high CO2 content gas field development in Malaysia. The reservoir selected is a carbonate buildup of middle to late Miocene age. This paper describes an integrated modeling approach to evaluate CO2 sequestration potential in depleted carbonate gas reservoir. Integrated dynamic-geochemical and dynamic-geomechanics coupled modeling is required to properly address the risks and uncertainties such as, effect of compaction and subsidence during post-production and injection. The main subsurface uncertainties for assessing the CO2 storage potential are (i) CO2 storage capacity due to higher abandonment pressure (ii) CO2 containment due to geomechanical risks (iii) change in reservoir properties due to reaction of reservoir rock with injected CO2. These uncertainties have been addressed by first building the compositional dynamic model adequately history matched to the production data, and then coupling with geomechanical model and geochemical module during the CO2 injection phase. This is to further study on the trapping mechanisms, caprock integrity, compaction-subsidence implication towards maximum storage capacity and injectivity. The initial standalone dynamic modeling poses few challenges to match the water production in the field due to presence of karsts, extent of a baffle zone between the aquifer and producing zones and uncertainty in the aquifer volume. The overall depletion should be matched, since the field abandonment pressure impacts the CO2 injectivity and storage capacity. A reasonably history matched coupled dynamic-geomechanical model is used as base case for simulating CO2 injection. The dynamic-geomechanical coupling is done with 8 stress steps based on critical pressure changes throughout production and CO2 injection phase. Overburden and reservoir properties has been mapped in Geomechanical grid and was run using two difference constitutive model; Mohr's Coulomb and Modified Cam Clay respectively. The results are then calibrated with real subsidence measurement at platform location. This coupled model has been used to predict the maximum CO2 injection rate of 100 MMscf/d/well and a storage capacity of 1.34 Tscf. The model allows to best design the injection program in terms of well location, target injection zone and surface facilities design. This coupled modeling study is used to mature the field as a viable storage site. The established workflow starting from static model to coupled model to forecasting can be replicated in other similar projects to ensure the subsurface robustness, reduce uncertainty and risk mitigation of the field for CO2 storage site.
The increase in production from hydraulic fracturing operations in recent years has had a dramatic effect on the oil and gas industry. However, as shale plays have taken up a larger percentage of the overall market, annual decreases in estimated ultimate recovery (EUR) values for shale wells is now a major concern for operators. At a presentation hosted by the SPE Gulf Coast Section, Ibrahim Abou-Sayed discussed how the adoption of drawdown management strategies have helped mitigate and reduce these losses. Abou-Sayed, the founder and president of i-Stimulation Solutions, also spoke about the elements of drawdown management that have been found to have the most significant impact on shale well productivity. In the presentation, titled "Shale Well Drawdown Management and Surveillance to Avoid EUR Loss and Impact on Refracturing," Abou-Sayed listed several parameters that affect production management strategies.
Wells in deepwater reservoirs show significant rate decline with time as the result of various causes. A diagnostic tool for quantification of factors influencing well-productivity decline is presented in this paper. The diagnostic tool helps identify well-stimulation candidates and potentially can help increase production. The work flow presented provides a tool for monitoring well-productivity changes to identify the main causes of productivity decline and to quantify effects on the normalized productivity index (PI). Most current and future deepwater reservoirs are in structurally deep, high-pressure environments in which reservoir and rock mechanisms that affect long-term well productivity are poorly understood.
Tight gas reservoirs and shale gas reservoirs are economically viable hydrocarbon prospects that have proved to be successful in North America. In such reservoirs, established methods of well testing and data analysis are often impractical. This paper presents an integrated well-test program developed for a tight gas reservoir in southwestern China. The program, designed and modified from conventional methods to meet the project-delivery timeline and cost constraints, makes use of a combination of various formation-evaluation techniques. The northwestern and central areas of the Sichuan basin have been identified as having basin-centered gas potential.
Abstract Well spacing and completion optimization in tight and shale reservoirs is a multi-dimensional task which comprise reservoir rock and fluid characterization, well performance study, inter-well communication analysis, and economic evaluation. Two sources of pressure data for characterization of inter-well communication include offset well pressure monitoring during hydraulic fracturing and controlled communication (interference) tests through staggered production. Both types of inter-well communication tests have become common among the operators in tight and shale reservoirs. However, quantitative analysis tools for interpretation of the test results are in their infancy. The focus of this study is quantitative analysis of pressure interference tests. In this study, an analytical model is developed for quantitative analysis of communication between multi-fractured horizontal wells (MFHWs) using pressure data from production and monitoring well pairs. The governing partial differential equation for the more general case of coupled flow in hydraulic fracture and matrix systems is solved using the Laplace transform. In order to validate the analytical model, the results from the analytical solution are compared against numerical simulation models. The analytical model of this study is applied to two field case from Montney formation. In these cases, a well from a multi-well pad is put on production and bottom-hole pressure of a monitoring well from the same pad is recorded using down-hole recorders. Communications between the wells is quantified using the analytical models of this study. The model of this study serves as a novel and practical tool for quantitative analysis and interpretation of inter-well communication in MFHWs. Integration of the model with other direct diagnostic and measurement tools can provide insight into optimized completion intensity for MFHWs.
Abstract Gas injection huff and puff (HnP) has been successfully applied in parts of Eagle Ford over the past few years. The success is attributed to gas and oil miscibility achieved by injection of gas at high pressure and rate in a contained hydraulic fracture system with a considerable of stimulated volume. Two key preliminary steps in gas HnP modeling include characterization of reservoir fluid (and its interaction with injected gas) and evaluation of hydraulic fracture system. This study focuses on simplified analytical tools for estimation of stimulated reservoir size from production data. Rate-transient analysis (RTA) is a tool for identification of flow regimes and estimation of key performance metrics for multi-fractured horizontal wells. The flow regimes include enhanced fractured region (EFR), bilinear flow, transient linear flow, transitional flow, and boundary-dominated flow. In this study, the size of stimulated rock and total effective fracture area are estimated using an RTA method. Further, diagnostics fracture injection tests (DFITs) and pressure buildup tests are used to characterize the multi-fractured horizontal wells for the purpose of gas EOR evaluation. Inter-well communication test is used to quantify the conductivity of connecting fractures between communication wells. This study helps the engineers and managers with reservoir and hydraulic fracture characterization and the screening process for gas HnP candidates. The outputs of these methods serve as first pass of SRV size for more detailed numerical modeling studies.
Gas injection huff and puff (HnP) has been successfully applied in parts of Eagle Ford over the past few years. The success is attributed to gas and oil miscibility achieved by injection of gas at high pressure and rate in a contained hydraulic fracture system with a considerable of stimulated volume. Two key preliminary steps in gas HnP modeling include characterization of reservoir fluid (and its interaction with injected gas) and evaluation of hydraulic fracture system. This study focuses on simplified analytical tools for estimation of stimulated reservoir size from production data.
Rate-transient analysis (RTA) is a tool for identification of flow regimes and estimation of key performance metrics for multi-fractured horizontal wells. The flow regimes include enhanced fractured region (EFR), bilinear flow, transient linear flow, transitional flow, and boundary-dominated flow. In this study, the size of stimulated rock and total effective fracture area are estimated using an RTA method. Further, diagnostics fracture injection tests (DFITs) and pressure buildup tests are used to characterize the multi-fractured horizontal wells for the purpose of gas EOR evaluation. Inter-well communication test is used to quantify the conductivity of connecting fractures between communication wells.
This study helps the engineers and managers with reservoir and hydraulic fracture characterization and the screening process for gas HnP candidates. The outputs of these methods serve as first pass of SRV size for more detailed numerical modeling studies.
Abstract In conventional draw test analysis, initial reservoir pressure has to be known with precision to aid primarily to determine near wellbore skin. Furthermore, in old wells, the initial reservoir pressure has to be attained before drawdown. For very old wells and tight reservoirs therefore it would take painfuly long shutin time to eventually attain the initial reservoir pressure before drawdown. In largely depleted reservoirs, it may be impossible to actually attain the desired initial reservoir pressure even after a long shutin! Efforts at obtaining the initial reservoir pressure in all these cases would only yield the remaining reservoir pressure since fluid had been produced from the reservoir. On a semilog plot of flowing wellbore pressures versus time, it is not possible to estimate the reservoir pressure to even validate the recorded pressure before shutin. In this paper, a procedure has been developed to overcome these challenges. The new method plots flowing wellbore pressures against dimensionless pressures on linear axes, assuming infinte-acting flow. The plot gives a straight line with intercept on the flowing wellbore pressure axis yielding the remaining reservoir pressure on extrapolation to dinensionless pressure of zero. Although, developed for horizontal well flow, it can be adapted for vertical well flow with minimal effort. Mathematical procedure employed is based on selection of relevant source and Green’s functions for a horizontal well during infinite-acting flow and assuming the well purely as a line source. A case pressure drawdown test selected for analysis using the method developed here yielded very close reservoir pressure compared to the reservoir being characterized.
Summary In a previous work, we introduced a three-parameter scaling solution that models the long-term recovery of dry gas from a hydrofractured horizontal well far from other wells and the boundaries of a shale reservoir with negligible sorption. Here, we extend this theory to account for the contribution of sorbed gas and apply the extended theory to the production histories of 8,942 dry-gas wells in the Marcellus Shale. Our approach is to integrate unstructured big data and physics-based modeling. We consider three adsorption cases that correspond to the minimum, median, and maximum of a set of measured Langmuir isotherms. We obtain data-driven, independent estimates of unstimulated shale permeability, spacing between hydrofractures, well-drainage area, optimal spacing between infill wells, and incremental gas recovery over a typical well life. All these estimates decrease to varying extents with increasing sorption. We find that the average well with median adsorption has a permeability of 250 nd, fracture spacing of 16 m, 30-year drainage length of 79 m, and a 30-year incremental recovery of 67%. Introduction Since 2012, the Marcellus Shale has been by far the most productive US shale play. Producing 25% of the total US dry natural gas, the Marcellus Shale currently produces at least three times more natural gas than any other major US shale play, including, in order of decreasing production, the Permian, Haynesville, Utica, Eagle Ford, Barnett, Woodford, Fayetteville, and Antrim shales (Figure 1). This high productivity has attracted significant attention from developers. The majority of drilling activities have taken place in two sweet spots: northeastern Pennsylvania, which primarily contains dry gas, and southwestern Pennsylvania and northern West Virginia, which produce liquid-rich gas (Popova 2017). Since leading US shale-gas production for the first time in 2012, the Marcellus Shale currently produces three times more than the Permian Basin, the runner-up shale-gas producer.