The objectives of this paper are to summarize effective Reserves estimation methods for use in unconventional reservoirs, and to propose systematic procedures for classification of Resources other than Reserves (ROTR) volumes. We propose optimal timing for application of decline curve analysis (DCA), rate transient analysis (RTA), and reservoir simulation. Using these techniques, we provide results for one well from a 38-well database in the Permian Basin wells (TX USA). We then describe how the volumes are classified and categorized and how those volumes move between Reserves and ROTR as more information becomes available.
We begin with the analysis of well performance, where we specify the information that is necessary for each estimation method. We then suggest procedures to identify the flow regimes using diagnostic plots, provide guidance on the application of multi-segment DCA models, and finally suggest procedures for the application of RTA and reservoir simulation. We continue with progress toward Reserves classification, starting with suggested procedures to reclassify Prospective Resources as Contingent Resources (upon discovery). We provide post-discovery guidance on development and commerciality for the project maturity sub-classes (within the Contingent Resources classification). We explain that “established technologies” must be technically and economically viable before they can be used for development decisions. And finally, we examine requirements to remove contingencies so that the volumes can be reclassified properly as Reserves.
Our major suggestions for well performance analysis are, first, that the multi-segment DCA approach is most effective in unconventional reservoirs when specifically relevant models are used for transient flow and boundary-dominated flow. Furthermore, we suggest that RTA using analytical models expands possibilities of forecasting for changes in well conditions and for well spacing studies. Though time and computationally time consuming, compositional simulation is required for confident analysis of near-critical reservoir fluids.
For movement of resources toward Reserves, we suggest that there is no linear path to define the movement from Prospective to Contingent Resources, though there are certain criteria which must be met for a given project. Certain contingencies, such as price of oil and available technologies, dominate the classification of resource volumes.
This paper provides a visual representation of when to use each Reserves estimation method depending on available data. We present a thorough analysis of best practices for each Reserves estimation method. We provide graphical representation of the movement between Prospective to Contingent Resources categories, the progression in chance of development and commerciality within project maturity sub-classes for Contingent Resources, and the contingencies that must be resolved to move from Contingent Resources to Reserves. Finally, we present an explanation of the criteria that must be met before volumes can be reclassified and/or recategorized from undiscovered to discovered.
Park, Jaeyoung (Texas A&M University) | Iino, Atsushi (Texas A&M University) | Datta-Gupta, Akhil (Texas A&M University) | Bi, Jackson (Anadarko Petroleum Corporation) | Sankaran, Sathish (Anadarko Petroleum Corporation)
The objective of this study is to develop a workflow to rapidly simulate injection and production phases of hydraulically fractured shale wells by (a) incorporating fracture propagation in flow simulators using a simplified physical model for pressure-dependent fracture conductivity and fracture pore volume (b) developing a hybrid Fast Marching Method (FMM) and 3D Finite Difference(FD) model for efficient coupled simulation and (c) automating the entire workflow for rapid analysis in a single simulator domain.
Pressure-dependent fracture transmissibility and pore volume multiplier models are assigned to predefined potential hydraulic fracture paths to mimic geomechanical behavior of fractures (i.e. opening and closure). The multipliers are based on empirical equations (e.g., Barton-Bandis model) and theoretical models (e.g., linear elastic fracture mechanics and cubic law). The FMM-based simulation transforms an original 3D reservoir model into an equivalent 1D simulation grid leading to orders of magnitude faster computation and is utilized to efficiently history-match field production and pressure data. A population-based history matching algorithm was used to minimize data misfit and quantify uncertainties in tuning parameters.
We demonstrate the effectiveness and efficiency of the proposed method using synthetic and field examples. First, we validated our proposed simplified fracture propagation model with a comprehensive coupled fluid flow and geomechanical simulator, ABAQUS. The results showed close agreement in both injection pressure response and fracture geometry. Next, the method was applied to a field case to history-match injection pressure and production data. Fracture geometry and properties were inferred from the injection phase and are input to the production phase modeling. After history matching, the misfit and uncertainty ranges in reservoir and fracture properties were substantially reduced.
The proposed workflow enables rapid analyses of hydraulically fractured wells and does not require computationally demanding geomechanical simulations to generate fracture geometry and properties. The FMM-based simulation further improves computational efficiency and allows us to automate the workflow using population-based history matching algorithms to quantify and assess parameter uncertainty.
The objective of our research is to reconcile the differences, in both age and relative stratigraphic position, between the Woodbine and Eagle Ford Groups in the outcrop and subsurface of the East Texas Basin. In the outcrop belt, organic- and carbonate-rich Middle Cenomanian mudstones are mapped within the Eagle Ford Group, where they overlie, and are separated by a regional unconformity from Early Cenomanian, organic-poor, and clay-rich mudstones of the Woodbine Group (Pepper Shale). In southern portions of the East Texas Basin, however, these same organic- and carbonate-rich Middle Cenomanian mudstones are mapped within the Maness Shale, which in turn, is overlain by Late Cenomanian to Turonian-aged mudstones (Pepper Shale) and sandstones (Dexter Formation) mapped as the Woodbine Group. Our approach to reconcile the lithostratigraphic juxtaposition between the two regions was to use chemo-stratigraphic and petrophysical data collected from the outcrops, as well as an adjacent shallow research borehole, in order to define key sequence stratigraphic units/surfaces, and then correlate the key units/surfaces from the outcrop belt into the subsurface.
Our research indicates that the Woodbine Group, is an older unconformity-bounded depositional sequence which is Early Cenomanian, whereas the Eagle Ford Group, is an overlying (younger) unconformity-bounded depositional sequence, which is Middle Cenomanian to Late Turonian. The unconformities that bound these units can be mapped from the outcrop belt into the subsurface of the East Texas Basin, to define coeval depositional sequences. As defined in this study, marine mudstones of the Woodbine Group, are clay- & silica-rich, TOC-poor, and characterized by low resistivity on geophysical logs. In general, the Woodbine Group thins, as well as transitions to more mudstone-prone facies, from northeast to southwest within the basin. While beyond the scope of this study, the Woodbine Group contains numerous higher-frequency sequences, which are stacked in an overall progradational (highstand) sequence set. The depositional profile of the unconformity which forms the top of this progradational succession sets up the relict physiographic (depositional shelf/slope/basin) profile for the overlying Eagle Ford Group.
Within the Lower Eagle Ford Formation, two high-frequency sequences, defined as the Lower and Upper Members, were defined. Within the Upper Eagle Ford Formation, three high-frequency sequences, defined as the Lower, Middle, and Upper Members, were defined. The Lower and Upper Members of the Lower Eagle Ford Formation, as well as the Lower Member of the Upper Eagle Ford Formation range from Middle Cenomanian to Early Turonian. These three high-frequency sequences contain marine mudstones that are carbonate- & TOC-rich, as well as clay- and quartz-poor, and are characterized by high resistivity values on geophysical logs. Furthermore, they are interpreted as a transgressive sequence set, with sequences that sequentially onlap, from older to younger, the inherited relict physiographic (depositional shelf/slope/basin) profile of the underlying Woodbine Group. In stark contrast, mudstones within the Middle and Upper Members of the Upper Eagle Ford Formation, which are Middle to Late Turonian, are clay-rich, TOC-poor, and characterized by low resistivity on geophysical logs. These two sequences, which are interpreted as a highstand sequence set, are sandstone-prone, and contain petroleum reservoirs that previously were incorrectly included within the Woodbine Group. Based on these correlations, updated sequence-based paleogeographic maps can be constructed for the first time across the East Texas Basin. These maps can in turn be used to define a robust portfolio of conventional, as well as unconventional tight-rock and source-rock, plays and play fairways, which are now based on a modern sequence stratigraphic, versus the traditional archaic lithostratigraphic framework.
Baek, Seunghwan (Texas A&M University) | Akkutlu, I. Yucel (Texas A&M University) | Lu, Baoping (Sinopec Research Institute for Petroleum Engineering) | Ding, Shidong (Sinopec Research Institute for Petroleum Engineering) | Xia, Wenwu (Harding Shelton Petroleum Engineering & Technology Limited)
Routine history-matching and reservoir calibration methods for horizontal wells with multiple hydraulic fractures are complex. Calibration of important fracture and matrix quantities is, however, essential to understand the reservoir and estimate the future recoveries. In this paper, we propose a robust method of simulation-based history-matching and reserve prediction by incorporating an analytical solution of production Rate Transient Analysis (RTA) as an added constraint. The analytical solution gives the fracture surface area contributing to the drainage of the fluids from the matrix into the fractures. The surface area obtained from the RTA is the effective area associated with the production—not total area. It is the most fundamental and the most significant quantity in the optimization problem. Differential evolution (DE) algorithm and a multi-scale shale gas reservoir flow simulator are used during the optimization. We show that the RTA-based optimization predicts the quantities related to completion design significantly better. Further, we show how the estimated total fracture surface area can be used to measure the hydraulic fracturing quality index, as an indication of the quality of the well completion operation. The most importantly, we predict that the fractures under closure stress begin to close much sooner (100 days) than the prediction without the RTA-based fracture surface area constraint. The deformation continues under constant closure stress for about 20 years, when the fractures are closed nearly completely. This work attempts to use the traditional reservoir optimization technologies to predict not only the reserve but also the life of the unconventional well.
The objective of this study was to perform flow simulation based-reservoir modeling on a two-well pad with a long production history and identical completion parameters in the Midland Basin. A reservoir model was built using properties generated from an established geomodel. Sensitivity analysis was performed during early history match to identify ‘heavy hitters’. Subsequent history matching was conducted with less than 10% of global error, and ranges of uncertain parameters have substantially narrowed as a result. The top 50 history-matched models are selected to predict Estimate Ultimate Recovery (EUR) followed by probabilistic analysis that shows P50 of oil EUR is within acceptable range of deterministic EUR estimates. Lateral spacing sensitivity was investigated with the best history-matched model to find the maximum volume and economic benefit by varying lateral spacing of a two-well pad. The results show that, given the current completion design, well spacing tighter than the current development practice in the area is less effective in terms of volume recovery yet economic values suggest that the optimum spacing for the area is around 150% of current development assumption for one section. The presented workflow provides a systematic approach to find the optimum lateral spacing in terms of volume and economic matrices per one section. Change in commodity price will shift optimum well spacing recommendation by suggested workflow. Similar methodology can be readily performed to evaluate spacing optimization in other acreage.
This paper presents methodology to analyze the reliability of reserves estimates filed with regulators in the U.S. and Canada. Using this methodology, we measured biases in the technical revisions presented in reserves reconciliation reports for 34 companies filing in Canada and 32 companies filing in the U.S from 2007 to 2017.
Filers in both Canada and the U.S. overestimated 1P reserves, and U.S. filers overestimated 1P reserves (51% positive technical revisions instead of 90%) more often than Canadian filers (72% positive technical revisions). Canadian filers underestimated 2P reserves slightly (54% positive technical revisions instead of 50%). Considering the entire reserves distribution, Canadian filers were moderately overconfident (underestimated uncertainty) and slightly pessimistic. U.S. filers, who report only 1P, were somewhere between (1) extreme overconfidence and neutral directional bias and (2) moderate overconfidence and extreme optimism.
Three groups of professionals can benefit from this study: (1) estimators, who can use the methodology to track their technical revisions over time, calibrate them, and use this information to improve future estimation procedures; (2) investors, who can analyze reported reserves estimates to compare volumes fairly; and (3) regulators, who will have quantitative methodology to suggest to filers to help them ensure that they are complying with appropriate criteria for 1P and 2P reserves and avoid significant reserves write-downs later.
Estimating reserves is an important process in most companies, as these estimates can have a large impact on company valuation. An estimate of reserves is inherently a probabilistic assessment; the different reserves categories (1P, 2P, 3P) quantify the uncertainty in this estimate. Unfortunately, humans are poor at assessing uncertainty; i.e., we are biased. Several authors have reported on the tendency for overconfidence and optimism in the petroleum industry (Capen 1976; Welsh et al. 2005; McVay and Dossary 2014).
Reliability in reserves estimates requires that, over a large number of these estimates, the frequency of outcomes would correspond to the probabilities of reserves stated by reserves definitions. Reserves volumes should be as reliable as possible so that investors can be confident they are comparing volumes fairly: “Tightly controlled and audited reserves volumes are meant to provide investors with the confidence that a barrel of reserves at Company A bears the same uncertainty as a barrel at Company B” (Beliveau and Baker 2003).
The completion design process for most horizontal wells in shale reservoirs has become a statistical evaluation process, rather than an engineering-based process. Our paper presents an alternative approach using an engineering approach to define the reservoir properties and the effectiveness of the fracture treatments. We then use these results in an economic analysis that allows the engineer to be predictive with respect to how capital is spent in the completion process.
This paper presents a methodology for both the evaluation of the reservoir and the design of the well completion where the engineer can make economic decisions and determine the change in the return on investment as a function of the change in capital expenditure. The engineer can then be able to “optimize” the completion and fracture treatment designs based on Net Present Value, Return on Investment or any other economic parameter desired. We use a rate transient analysis approach to estimate reservoir and fracture properties. We present case histories in the paper, and the interpretation of the production analyses of these case histories yields information about the formation permeability and the effective lengths and number of hydraulic fractures created during the completion process.
With knowledge of the reservoir and fracture properties in hand, the engineer can then determine the “optimum” completion design for future wells. This understanding can be achieved much quicker and for much less money than the cost to drill the number of wells necessary to make statistical analysis meaningful. The results of the case histories indicate that many completion designs are not in the “optimum” range. Too much capital is being spent increasing stage count when it should be going to increased effective length. The focus on early-time production has ignored the effect that more fractures has on ultimate recovery.
The results and conclusions in this paper will run contrary to much of the direction most unconventional completion designs have been evolving over the past 5 to 10 years. A much greater emphasis on achieving increased effective lengths will be demonstrated and that increased stage count can prove detrimental to economic success over the well's life. Processes in the paper will also prove valuable for smaller operators that do not have a large well counts that are usually required to achieve a meaningful statistical evaluation.
An integration of fracture model and reservoir model with complex fracture geometry plays an important role in understanding the impacts of fracture complexity on optimization of well spacing. In this study, we applied the non-intrusive EDFM (Embedded Discrete Fracture Model) technology to couple fracture and reservoir models to perform shale gas simulation with and without considering natural fractures. First, we applied a complex fracture propagation model to predict hydraulic fracture geometry. For the first time, the impact of non-uniform natural fracture distribution with a larger fracture intensity nearby the wellbore region on fracture complexity was investigated. Two horizontal wells with and without natural fractures were simulated to generate simple and complex fractures. Complex fractures include hydraulic fractures and complex activated natural fractures. Well interference due to hydraulic fracture hits of both fracture geometries were analyzed and compared. After that, both simple and complex fractures were directly transferred to a shale-gas two-phase reservoir model through the non-intrusive EDFM technology. Both fracture geometries can be easily embedded into the structured matrix grids. Fluid flow between fracture and matrix grids can be exactly handled by non-neighboring connections and transmissibility. During the shale-gas production simulation, key effects such as non-Darcy flow in fractures, gas desorption, and pressure-dependent matrix permeability, hydraulic fracture permeability, and activated natural fracture permeability were considered. Additionally, different relative permeability curves for matrix and fractures were assigned in the reservoir model. We compared the well performance of 30 years under the constant flowing bottomhole pressure constraint between simple and complex fractures. The simulation results show that complex fractures can perform much better in terms of cumulative gas and water production than the simple fractures. The simple fractures are easier to cause well interference due to hydraulic fracture hits than the complex fractures under the same completion condition. Furthermore, the simple fractures have a much smaller drainage area and less drainage efficiency than the simple fractures. Finally, the simple fractures have a much larger pressure difference from the fracture center to its neighboring shale matrix than the complex fractures, which indicates that the smaller cluster spacing might be suggested in order to maximize the drainage efficiency if ignoring the natural fracture effect. This study provides critical insights into understanding the impact of non-uniform natural fractures on fracture propagation and shale-gas production simulation.
This work presents a novel methodology to predict multiphase flowrates using early-time flowback data (flowrates and measured bottomhole pressures) from wells in unconventional reservoirs. The methodology is entirely data-driven using the total liquid productivity index [JTL(t)] as a function of time, both diagnostically for the identification of flow regimes as well as fitting the JTL(t) data trend with a "hyperbolic" decline function, which is later used as a forecast relation. The second major component of this methodology is the use of measured flowing bottomhole pressure data [pwf(t)], which is also correlated, or fit, with a "hyperbolic" decline function for forecasting purposes. The JTL(t) model is extrapolated in time, as is the independent pwf(t) model, and both models are then combined to forecast the total liquid flowrate. The individual phase flowrates are then predicted from the total liquid flowrate using the average water cut and average GOR observed during early-time flowback.
This work is not bound by any physical constraints, and the "physics" of the process are implicit in the use of the independent hyperbolic decline models used for the JTL(t) and pwf(t) functions. Other, perhaps more rigorous models could be used, but such applications are beyond the scope of the present work. To calibrate the proposed JTL(t) and pwf(t) hyperbolic models, we initially focus solely on the use of early-time flowback data, but we also demonstrate that continuous updating of the calibrations with 30, 60, 90, and 120 days of production history provides a more robust prediction of long-term performance. The most significant, or limiting, assumption is the character and nature of the flowing bottomhole pressure behavior [pwf-model(t)], of which the model implicitly assumes the production operations remain constant (i.e., a constant choke and no shut-ins). This limitation is generally less important in practice, however, cases with longer term shut-ins are problematic, particularly when such shut-ins occur at early-times or during flowback.
Growth in a number of newly drilled wells in unconventional reservoir development results in tightly spaced horizontal wells, which consequently creates well interference (fracture hits) between parent and infill wells as a result of stress redistribution from localized pressure sink zone in parent wells. This directly affects the production performance of both parent and infill wells. In order to minimize this effect, it is sometimes more preferable to place an infill well in a different pay zone. However; due to poroelastic effect, pressure depletion from the parent well also affects stress distribution in different pay zones and yet only a few literatures focus on this effect. The main objective of this paper is to predict temporal and spatial evolution of stress field for Permian basin using an in-house 3D reservoir-geomechanics model and propose guidelines for determining lateral and vertical drilling sequence of infill wells to mitigate well interference.
Embedded discrete fracture model (EDFM) is coupled with a sequentially coupled reservoir-geomechanics model to gain capability in simulating complex fracture geometries and high-density fracture system. Different scenarios with and without natural fractures were studied including a case where two parent wells are located in different layers (Wolfcamp A2 and B2) and a case where two parents are located in the same layer (Wolfcamp A2 and B2). Stress redistribution is then observed to determine the completion sequence of infill wells in different layers.
Producing two parent wells in the same pay zone results in large stress redistribution mostly in the area close to fracture tips at an early time. As time progresses, stress redistribution area becomes larger and covers almost entire infill well zone in Wolfcamp B2. Stress changes can also be observed in Wolfcamp A2 and A3 despite producing wells are only located in Wolfcamp B2. However, when producing two parent wells in different pay zones, stress redistribution can only be observed near fracture tips in both Wolfcamp A2 and B2 with minimum stress change in the infill zone even at a later time in all Wolfcamps A2, A3, and B2. This allows the possibility of producing infill well in the un-depleted layers (i.e. A3) enhancing efficiency of infill well completion. Fracture penetration and larger fracture length also play a significant effect in stress reorientation and evolution. Presence of natural fractures causes stress reorientation to occur at an earlier time due to higher depletion rate. This paper presents the possibility of changing the sequence of stacked pay from lateral well layout to vertical well layout in order to mitigate well inference and improve production performance of both parent and infill wells. Less stress change in the infill zone for vertical well layout makes it become superior to lateral well layout in which large stress redistribution can be observed.