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Abstract Market-induced production shut-downs and restarts offer us an opportunity to gather step-rate and shut-in data for pressure transient analysis (PTA) and rate transient analysis (RTA). In this study, we present a unified transient analysis (UTA) to combine PTA and RTA in a single framework. In this new approach continuous production data, step-rate data, shut-in data and re-start data can be visualized and analyzed in a single superposition plot, which can be used to estimate both and infer formation pore pressure in a holistic manner by utilizing all available data. Most importantly, we show that traditional log-log and square root of time plots can lead to false interpretation of the termination of linear-flow or power-law behavior. Field cases are presented to demonstrate the superiority of the newly introduced superposition plot, along with discussion on the calibration of long-term bottom-hole pressure with short-term measurements.
The Wheatstone gas field located in the Northern Carnarvon Basin offshore Western Australia achieved first gas in mid-2017. All seven foundation producers are equipped with permanent downhole gauges (PDHGs) for real-time pressure monitoring. Data from these gauges have been instrumental in understanding dynamic reservoir performance and reducing static uncertainties. The scope of this paper specifically covers the use of pressure and rate transient analyses (PTA and RTA) and the insights that have been gained during the first two years of production.
Significant offset distances exist between each PDHG and the reservoir. Corrections were developed to convert the gauge pressure to a reservoir datum, which primarily account for frictional and gas density changes with varying rates and temperatures within the wellbore. Other physical constraints and effects have been found to be more challenging to overcome, limiting the quality and interpretability of the pressure transients, particularly in the middle-time region. These include interference from non-reservoir pressure signals such as liquid fallback during shut-in, extremely low signal-to-noise ratios in the higher quality formations, and proximity to boundaries that render a short infinite-acting radial flow (IARF) period that could be masked by wellbore storage.
Attempts to circumvent these issues have included the use of drawdown transient analysis to complement build-ups. The step-rate test can eliminate liquid fallback entirely, which allows for better resolution of the IARF period. Rapid choke movements were also trialled to boost the reservoir response in some instances. Interpretations using the drawdown data were further verified in one producer through analysis of the buildup data acquired following a routine downhole safety valve closure, which benefitted from the trapping of condensed liquid above the closed valve. This provided the cleanest PTA data seen outside of drill stem testing during field appraisal. While successful in the example presented, no methods have yet been found to reliably increase IARF interpretability in those wells producing from the best quality sands.
Regarding RTA, the authors have found very few documented cases in the literature of applying this technique to conventional gas fields. To field-test its applicability in such an environment, evaluations of drainage volume by producer were performed and found satisfactory when compared with other estimates of gas in-place. It is hoped that a presentation and discussion of this finding will be additive to the reservoir engineering toolkit.
Lack of long-term production data is one of the major challenges when performing analysis for tight gas reservoirs during appraisal phase. For low-permeability liquid-rich gas and gas condensate reservoirs, fracture performance will be severely affected by condensate banking as soon as dew point pressure is reached in the vicinity of the wellbore. This makes the evaluation of fracture effectiveness and potential connected volume more challenging. Although numerical simulation can account for complex PVT, reservoir and fracture characteristics and by far the most rigorous method for forecasting, it cannot be applied to all wells due to lack of analysis time and supporting data. Therefore, a more robust methodology is required to analyze production data for a limited test period during the development phase. This paper entails an efficient and robust methodology that was applied to over 80 wells in less than a few weeks for performance evaluation, history matching and forecasting. The field in this study is a layered tight gas reservoir in the Middle East, which is currently undergoing development after an extensive appraisal plan. Most of the wells are single staged vertically fracced with their performance being significantly in comparison due to the hydraulic fracturing performance, rock quality, gas richness and operating conditions. With over 100 wells planned to be drilled in this field, it is vital to analyze the existing well performances and establish a workflow emphasizing on the near wellbore region for a robust forecasting methodology for this tight liquid-rich reservoir.
Qin, Jiazheng (China University of Petroleum-Beijing, The University of Texas at Austin) | Cheng, Shiqing (China University of Petroleum-Beijing) | Zhu, Jing (Drilling & Production Technology Research Institute, Liaohe Oilfield) | He, Youwei (Southwest Petroleum University) | Yu, Wei (SimTech LLC, The University of Texas at Austin) | Rui, Zhenhua (Massachusetts Institute of Technology) | Sepehrnoori, Kamy (The University of Texas at Austin)
Well interference has been historically investigated by pressure transient analysis, while it has shown that rate transient analysis has great potential in well interference diagnosis. However, the impact of complex fracture networks (CFN) on rate transient behavior of parent well and child well in unconventional reservoirs is still not clear. To further investigate, this paper develops an integrated approach combining pressure and rate transient analysis for well interference diagnosis considering CFN.
To perform multi-well simulation considering CFN, non-intrusive embedded discrete fracture model approach was applied for coupling fracture with reservoir models. The impact of CFN including natural fractures and frac-hits on pressure and rate transient behavior in multi-well system was investigated. Obvious distinctions could be viewed for different kinds of CFN on diagnostic plots compared with single-well model. Due to the interference from surrounding producers, new flow regimes including compound linear flow and interference flow would occur on loglog plot. In general, the effect of natural fractures seems to be more evident than that of frac-hits. Blasingame plots could be categorized into different types based on various CFN patterns.
Application of this integrated approach to demonstrates that it works well to characterize the well interference among different multi-fractured horizontal wells in a well pad. Better reservoir evaluation can be acquired based on the new features observed in the novel model, demonstrating the practicability of the proposed approach. The combination of pressure and rate transient analysis can reduce the uncertainty and improve the accuracy of the well interference interpretation based on both field pressure and rate data.
This paper presents an analytical model for full-flow-regime rate-transient analysis in unconventional volatile oil reservoirs. The model allows us to forecast long-term production based on transient production data and will be applicable in wells with substantial water production. We formulated and solved governing non-linear partial differential equations (PDEs) with an inner boundary condition of constant BHP. By defining pseudo-variables to transform the governing non-linear PDEs to linear forms, we were able to find solutions of pseudopressure-normalized rate for oil, gas and water phases that describe all flow regimes over the life of a multi-fractured horizontal well. For one-dimensional flow in closed reservoirs, our analytical solutions that show the relationship between pseudopressure-normalized rate and dimensionless time indicate a complicated decline with an exponential relation inside an infinite series. Our study also highlighted that simply using uncorrected PVT data without removing separator effects can be in error. More importantly, to provide an accurate pseudopressure calculation, we conducted numerous simulation studies and proposed saturation-pressure (S-P) relations to enhance the accuracy of calculated pseudopressures specifically for various volatile oils. Our analytical methods yielded reasonable interpretations of not only simulated data but also actual field data. The solutions were validated through comparisons with results from compositional simulation; the good agreements for both ordinary and near-critical volatile oils verified the accuracy of our analytical method; notably, the validations were almost exact during boundary-dominated flow. We also applied our methods to analyze production data from two wells in shale oil reservoirs in the Midland Basin. These cases illustrated that our model can handle with wells not only in transient (infinite-acting) flow but also in boundary-dominated flow.
Tight/shale oil development has increased significantly since 2010, driven by technological improvements that have reduced drilling costs and improved hydraulic fracturing technology in major tight/shale plays such as the Bakken, Eagle Ford, Permian Basin, and other resources through the world (EIA 2017). The U.S. Energy Information Administration also reported that the total reserves of shale oils worldwide are over three hundred billion barrels. In the next twenty years, successful development of these reservoirs will still be crucial to maintain current oil supplies and further to achieve even greater production and reserves levels. Because of the way hydrocarbons originated and accumulated in tight/shale rock formations, light oils have been found to be common fluids in most of these reservoirs. In production of these less-dense crude oils, we observe substantial gas flow, resulting in significant reduction of oil production once reservoir pressure drops below bubblepoint pressure. The industry urgently needs an accurate and practical method to forecast production, especially an analytical approach for field application to unconventional volatile oil reservoirs.
Muhammad, Danish (Pakistan Oilfields Limited) | Hussain, Sadam (Pakistan Oilfields Limited, Univeristy of Oklahoma) | Hassan, Mohsin (Pakistan Oilfields Limited) | Zakir, Mufaddal Murtaza (Pakistan Oilfields Limited) | Qazi, Shoukat Elahi (Pakistan Oilfields Limited) | Ali, Shahzad (Pakistan Oilfields Limited) | Haleemuddin, H. M (Pakistan Oilfields Limited)
In Potwar Basin, Tight Naturally Fractured carbonate reservoirs usually have matrix porosity of the 2-3% and permeability less than 1 mD. It is very challenging to evaluate Gas initial in-place (GIIP) and reserves accurately in these type of reservoirs. The objective of this study is to evaluate Gas in-place and to characterize the reservoir energy mechanism using rate transient analysis (RTA). A comparison has also been made for Gas in-place from conventional material balance analysis and from rate transient analysis.
In this study, rate transient analysis has been performed in a well, located in Potwar with thirteen years of production history. The well is completed in Chorgali and Sakesar formations. Different scenarios of initial reservoir pressure, geo-mechanical effects during initial production of the well and aquifer volume were sensitized to evaluate the Gas initial in-place (GIIP) and reserves. Different type curves such as Agarwal Gardner, Blasingame and flowing material balance and analytical aquifer modelling with / without geo-mechanical effects were applied and matched with the production history. Production logging data was also incorporated in the study. During history matching (gas-rate and bottom-hole flowing pressure), different sensitivities were run to quantify the uncertain parameters and level of uncertainty in the simulator.
While history matching and evaluating GIIP/reserves, it was observed that 8,060 psi reservoir pressure measured in the well was not stabilized and the reservoir was dominated initially by geo-mechanical effects. The best match was achieved with 10,935 psi initial reservoir pressure which was measured in the first well of the field. Without considering this pressure and geo-mechanical effects, the best match could not be obtained. It was also confirmed by different type curves that reservoir was geo-mechanically pressured during the early life of the well and also, it has a weak aquifer support during the late life of the well. The GIIP evaluated from these type curves are in the range of 75-90 BSCF whereas conventional material balance showed 60-70 BSCF indicative volume associated with the well. This study exhibited a significant difference in GIIP/reserves evaluated from conventional material balance and rate transient analysis, indicating remaining hydrocarbon potential in the region i.e. approximately 10-13 BSCF.
If the static reservoir pressure is taking too long to stabilize, the conventional material balance approach always depicts lower hydrocarbon volume associated with the well due to the tight and heterogeneous nature of the reservoirs. Therefore, conventional material balance cannot be applied in these reservoirs and unconventional approach such as rate transient analysis should be applied to evaluate GIIP / reserves and reservoir energy mechanism.
Abstract Oil industry knows dozens of hundreds of different EOR/IOR methods to improve reservoir recovery efficiency. Among today's priorities are assessment of various EOR/IOR and bottomhole treatment technologies and selection of the most effective ones that will meet the specific reservoir conditions. For assessment of stimulation efficiency, different techniques can be used: decline curve analysis (DCA), production rates analysis before and after stimulation, analysis of reservoir properties in the near-wellbore zone and in the reservoir using pressure build-up (PUB) curves. Each technique has advantages and disadvantages. Thus, comparison of production performance ignores bottomhole pressure changes before and after stimulation, pressure buildup curves are not infrequently of a rather low quality, DCA is based on empirical relationships liable to misinterpretation because of subjective estimate. Devoid of these drawbacks is the rate transient analysis (RTA). The advantage of this method is that it makes allowance for change of production rates always occurring following stimulation. This is achieved through use of diffusion equations. Practice has shown that RTA provides a comparative analysis of production rates and cumulative oil production through time, porosity and permeability before and after stimulation, being, thus, a comprehensive tool for efficiency evaluation. Variation in oil production is the most reliable parameter, because it accounts for changes in bottomhole pressure and water cut before and after stimulation. To determine this parameter, an algorithm based on the pressure drop change is offered. RTA allows production forecast by two scenarios, the scenario involving stimulation, and the scenario without any production enhancement operations with a view to assess cumulative incremental production. In conclusion, it can be said that rate/pressure transient analysis allows assessment of efficiency of a large variety of EOR/IOR projects and a long-term production forecast. The offered approach may serve a good alternative to the decline curve analysis and comparison of production rates and PUB curves before and after stimulation.
This paper presents a simple yet rigorous analytical solution for two-phase (gas-oil) flow in closed volatile oil reservoirs. The solution includes all flow regimes over the life of a multi-fractured horizontal well, including the usually long-duration early transient flow followed by the transition and the boundary-dominated flow regimes. The solution will be particularly useful in rate transient analysis of production data and production forecasting for horizontal wells with multiple fractures in ultra-low permeability reservoirs, such as shales. We formulated the governing, non-linear partial differential equations (PDEs) for simultaneous gas-oil flow with an inner boundary condition of constant bottom-hole pressure (BHP). We then defined pseudo-variables to transform the non-linear PDEs to linear forms. By developing deterministic models for calculation of fluid properties using multi-regression analysis of PVT data and relative permeability curves, we were able to find analytical solutions by the separation of variables method for specified initial and outer boundary conditions. We obtained a production rate-time relation which can be used to generate type curves or to provide a basis for history matching production data and forecasting future production. Under constant bottom-hole pressure producing condition, the resulting solutions that describe the relationship between dimensionless rate and dimensionless two-phase pseudotime indicate a complicated decline with an exponential relation inside an infinite series. We validated the solutions through comparisons with compositional simulation using commercial software; the satisfactory agreements demonstrated the accuracy and utility of the analytical solutions. Our results indicate that the production performance in multi-phase flow is far different than performance in single-phase flow, and that formation properties interpreted using techniques appropriate for single-phase flow can be seriously in error when applied to two-phase flow situations. Finally, we found that our analytical solution yielded reasonable interpretations of actual field data from the Midland Basin.
Abstract Recent advances in data acquisition systems have helped in monitoring wells performance and recording their production parameters like pressure, temperature and valve opening in real time with high frequency. A cost-effective technology to estimate well production rates is Virtual Metering, which integrates real time data and analytical models. This paper presents the methodology of an innovative virtual metering tool and the promising results obtained in real case applications on gas, gas condensate and oil fields. A Virtual Metering tool has been developed by integrating a commercial software platform and mathematical models (algorithms). The algorithms solve simultaneously dynamic pressure and temperature gradients (VLP) along with the choke equation to find the optimal solution rates that match physical sensor readings. Moreover, the tool manages the communication between real time data and the models enabling a safe storage of the results. Models require a manual calibration at reference dates based on well separator tests or MPFM readings, in a way to match total field production. After calibration, the algorithm is able to run automatically in real-time. Three implementations are presented about gas, gas and condensate and oil fields, showing the benefits and limitations of virtual meter application. Virtual meter proved to be a valid technology with the potential of even replacing MPFM results, especially in dry gas fields. Where MPFM are installed on each wellhead, virtual meter worked as redundant system and allowed to detect precociously flow meters malfunctioning. The allocation workflow has been modified in order to replace MPFM estimations with virtual meter ones. For oil fields with variable production parameters, the tool has provided reliable independent rate estimation by combining VLP and choke calculator in a unique optimization tool. The real time flow rate can be used as a basis for pro-rata allocation of fiscal production in the framework of a Production Data Management System software. Additional features of the tool are the following: a real-time input for pressure and rate transient analysis and a workflow for real-time well drawdown estimation of gas wells, which makes use of automatic p/z reservoir model update to estimate reservoir pressure. Moreover, this tool had a significant impact on production monitoring, improved the effectiveness of production optimization actions and the quality of history match of reservoir 3D model. This paper contains a novel approach of a reliable and robust virtual metering tool that can be flexibly applied to gas and oil fields through a unique optimization algorithm, which is able to combine information coming from production network and from the reservoir side. It gives benefit to company workflows by feeding external reservoir analysis applications that would not be possible without virtual meter results and uses the results of external applications for validation purpose.