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Collaborating Authors
Lee, John
Summary This paper incorporates the findings of our previous publication (Morales and Lee 2022) and identifies, isolates, and quantifies elements in the annually disclosed proved reserves revisions that should not be considered technical or economic revisions. This has resulted in significantly different technical and economic revisions compared to those simplistically and directly derived using a common interpretation of the Financial Accounting Standards Board (FASB) Topic 932-235-50-5 (a) definition. We have assessed the reliability and comparability of the updated technical revisions when used to judge the reasonable certainty of the underlying proved reserves. We have carried out the analysis separating the proved reserves into developed and undeveloped. To derive a realistic data set to generate the updated technical and economic revisions, we reviewed more than 1,000 annual reports (10K and 20F Forms) and more than 600 comment letters from 141 companies filing annual reports to the Securities and Exchange Commission (SEC) during the period 2010–2020, extracting the information related to annual reserves changes and explicitly focusing on the disclosed revisions of previous estimates (RPE). We present evidence showing that the approach followed is robust and more reliable than the simple approach where technical revisions are estimated by simply subtracting the disclosed revisions due to price effects from the disclosed revisions in annual reports. The root causes for the significant differences between the simplistic approach and the one presented in this paper are mainly due to (1) including annual reserves changes due to nontechnical or economic factors as technical revisions, (2) using different interpretations of SEC and FASB regulations, and (3) not providing critical disaggregation information needed to estimate technical, economic, or other types of revisions correctly. Without proper consideration of these issues, the derived technical and economic revisions from disclosed data can be significantly distorted, affecting any conclusions derived. The annual average changes in technical revisions during a representative period, if correctly estimated, can provide an indication of both overstated and understated certainty of proved reserves estimates, which can impact a company’s relative valuation, asset impairment, internal depreciation, profit/loss, standardized measure, unit development costs, and other indicators based on proved reserves, making the reliability of the technical revisions and their actual upward or downward movements of paramount importance. We also highlight the significant different root causes driving the major differences between developed and undeveloped reserves in their annual technical revisions. The results indicate that for some companies that provide most of the information required for proper analysis, the certainty level of their disclosed developed and undeveloped proved reserves points toward an apparent overestimation of historically disclosed proved reserves. Our analysis shows the dubious quality and lack of reliability and comparability of the disclosed proved reserves revisions and highlights the limited value of existing guidance and current practices. We provide evidence that calls for FASB and SEC to provide complementary guidance in critical areas that currently limit the value, reliability, and comparability of the proved reserves revisions disclosed.
- Research Report > New Finding (0.46)
- Research Report > Experimental Study (0.46)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Semi-Analytical Model of A Multi-Well System with well Interference During Underground Gas Storage
Chu, Hongyang (School of Civil and Resources Engineering, University of Science and Technology Beijing, 100083 Beijing, China Harold Vance Department of Petroleum Engineering, Texas A&M University, 77843 College Station, USA) | Ma, Tianbi (Petroleum Exploration and Production Research Institute, SINOPEC, 100083 Beijing, China) | Jiao, Yuwei (Research Institute of Petroleum Exploration & Development, 100083 Beijing, China) | Zhu, Weiyao (School of Civil and Resources Engineering, University of Science and Technology Beijing, 100083 Beijing, China) | Zou, Jiandong (Research Institute of Exploration and Development, Changqing Oilfield Company, PetroChina.) | Pan, Yuewei (PetroChina Exploration & Production Company, Beijing, China) | Gao, Yubao (School of Civil and Resources Engineering, University of Science and Technology Beijing, 100083 Beijing, China) | Lee, John (Harold Vance Department of Petroleum Engineering, Texas A&M University, 77843 College Station, USA)
Abstract Underground gas storage (UGS) is an important source for regulating natural gas supply. The large injection or production rate causes well interference in UGS to be particularly serious. Current well testing workflows for UGS assume a single well. This paper proposes a novel multi-well solution and related analysis method to analyze targeted well performance in a multi-well system. On the basis of the constant rate solution, Laplace transforms, and the superposition principle, we obtained multi-well solutions for transient flow. A systematic validation of the proposed method was conducted using a commercial numerical simulator for cases of gas storage and recovery process in UGS. Results show that the long-term gas injection and production process in UGS further exacerbates the influence of formation heterogeneity and interference. As adjacent wells are producing, the pressure derivative finally exhibits pseudo radial flow of the multi-well system under the influence of well interference. The horizontal derivative value is related to the dimensionless production rate of the target well, adjacent wells, mobility ratio, and the traditional 0.5 value. When adjacent wells are injecting, the last flow that appears in the derivative curve shows a drop-off feature. Our methodology applied to analysis of UGS performance in the Hutubi gas reservoir in China provides better estimates of the in-place natural gas resource and formation properties in this multi-well system. The methodology also provides a consistent and direct analysis of reservoir performance when "well interference "effects are observed.
- Asia > China (1.00)
- North America > United States > Texas (0.46)
- Asia > China > Xinjiang Uyghur Autonomous Region > Junggar Basin (0.99)
- Asia > China > Shanxi > Ordos Basin > Changqing Field (0.99)
- Asia > China > Shaanxi > Ordos Basin > Changqing Field (0.99)
- (3 more...)
Abstract If properly estimated, technical revisions to disclosed proved reserves can be used to establish the reasonable certainty of both proved developed and undeveloped reserves. The trends in these technical revisions are important because they should result in overall positive revisions in EUR within a representative time period. If this criterion is not met, then the proved status of the reserves disclosed becomes questionable with the implications that this may have in depreciation, profit and loss, impairment tests and other reserves indicators where proved reserves are used. Unfortunately, in our review of the annual proved reserves revisions of developed and undeveloped proved reserves disclosed by companies to the SEC, we identified different interpretations and inconsistencies in the annual changes of proved reserves. We used data from annual reports issued between 2010 and 2020 by 141 companies, complemented by hundreds of comment letters issued by the SEC during this period, and found that companies did not apply the regulations and standards consistently, highlighting the limited effect the SEC comment letters have had in improving clarity and understanding in this important area of reserves estimation and categorization. We identified several issues which, if not carefully considered, may lead to incorrect interpretations and conclusions regarding the reliability and comparability of the disclosed proved reserves annual changes and their embedded level of certainty. The paper highlights different interpretations of key definitions and the different approaches and practices that seem to exist in companies when evaluators estimate, categorize, and disclose annual proved reserves changes due to revisions, improved recovery and extensions and discoveries, with special focus on isolating the technical revisions. We also show that the approach that some companies use to estimate the impact of changes due to changes in economic factors in the disclosed proved reserves leads to incorrect estimates and distorts the overall results or comparisons between companies. The evidence shown in the paper calls for improved and systematic official guidance if the proved reserves disclosures are to be used in a practical and useful manner. In the absence of such official guidance, this paper provides a simple project-based framework that may be used to properly analyze and extract value from the disclosed annual changes of proved reserves to improve the alignment, consistency, and proper interpretation of the disclosed proved reserves information and ensure that annual reserves changes do not end up being useless, impractical, or unreliable.
- North America > Canada > Alberta (0.28)
- North America > United States > Texas (0.28)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Louisiana > Delhi Field (0.99)
- North America > United States > Kentucky > Illinois Basin (0.99)
- (2 more...)
Abstract This paper provides a workflow to automate the application of multi-segment Arps decline model to forecast production in unconventional reservoirs. Due to significant activity in the shale plays, a single reservoir engineer may be tasked with managing hundreds of wells. In such cases, production forecasting using a multi-segment Arps model for all individual wells can be a challenging and time-consuming process. Although popular industry software provide some relief, each approach has its individual limitations. We present a workflow to automate the application of multi-segmented Arps decline model for easier and more accurate production forecasting using suitable statistical and machine learning methods. We start by removing outliers from our rate normalized pressure (RNP) data using angle-based outlier detection (ABOD) technique. This technique helps us clean our production data objectively to improve production forecasting and rate transient analysis (RTA). Next, we correct the non-monotonic behavior of material balance time (MBT) and smooth the RNP data using a constrained generalized additive model. We follow it by using the Ramer–Douglas–Peucker (RDP) algorithm as a change-point detection technique to automate the flow regime identification process. Finally, we calculate a b-value for each identified flow regime and forecast future production. We demonstrate the complete workflow using a field example from shale play. The presented workflow effectively and efficiently automates the rate transient analysis work and production forecasting using multi-segment Arps decline model. This results in more accurate production forecasts and greatly enhanced work productivity. The workflow presented, based on selected algorithms from statistics and machine-learning, automates multi-segment Arp’s decline curve analysis, and it can be used to forecast production for a large number of unconventional wells in a simple and time efficient manner.
- North America > United States > Texas (1.00)
- North America > Canada (0.70)
A Novel Semi-Analytical Model for the Multiwell Horizontal Pad with Stimulated Reservoir Volume
Chu, Hongyang (University of Science and Technology Beijing) | Ma, Tianbi (Petroleum Exploration and Production Research Institute, SINOPEC) | Gao, Yubao (University of Science and Technology Beijing) | Zhu, Weiyao (University of Science and Technology Beijing) | Lee, John (Texas A&M university)
Abstract Recently, there have been many attempts to model the stimulated reservoir volume in unconventionls. However, most researches only focused on the intersecting hydraulic or natural fractures and the effects of stimulated reservoir volume are ignored. In this study, we developed a new method that uses an effective semi-analytical method to model the stimulated reservoir volume in unconventional reservoirs. Large-scale hydraulic fracturing not only forms hydraulic fractures but also activates a large number of natural fractures in the near-well region. To the best of our knowledge, most of the multiwell horizontal pad modeling methods ignore the physics of stimulated reservoir volume. Our semi-analytical model has the ability to simulate the behaviors of a multiwell horizontal pad with irregular shaped stimulated reservoir volume and impermeable boundary. Results show that the transient pressure behavior of the multiwell horizontal pad with stimulated reservoir volume is significantly different from that of a single isolated well. The linear flow among wells, the pseudo radial flow of multiwell in stimulated reservoir volume, and transitional flow, and final pseudo radial flow of multiwell correspond to completely different transient pressure response. The high flow ability in stimulated reservoir volume means a faster rate of pressure diffusion and it lead to the appearance of these flow regions in advance. The results also confirm that as the scale of stimulated reservoir volume increase, the flow duration influenced by the stimulated reservoir volume is longer. The stimulated reservoir volume and offsetting wells makes the pseudo-radial flow feature insignificant. The pressure and the pressure derivative exhibit a gradual rise feature. For the pseudo-radial flow in stimulated reservoir volume, the horizontal line value is related to the total production of the well pad. For the unstimulated region, this value is also related to the mobility ratio.
- Asia (0.68)
- North America > United States > Texas (0.28)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- (2 more...)
Rate/Pressure Transient Analysis of a Variable Bottom Hole Pressure Multi-Well Horizontal Pad with Well Interference
Chu, Hongyang (School of Civil and Resources Engineering, University of Science and Technology Beijing) | Liao, Xinwei (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum Beijing) | Wei, Cao (Harold Vance Department of Petroleum Engineering, Texas A&M University College Station) | Lee, John (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum Beijing)
Abstract Multi-well horizontal pads are common in unconventional reservoirs. With addition of infill wells and hydraulic fracturing, interference between multiple multi-fractured-horizontal wells (MFHWs) has become a serious issue. Current RTA workflows assume a single MFHW in the unconventional formation. This paper presents a new multi-MFHW solution and related analysis methodology to analyze targeted well rate performance in a multi-MFHW system. In this work, a semi-analytical equation describing multi-well pad in the Laplace domain with well interference is proposed. The proposed semi-analytical model can simulate the rate performance of a multi-well horizontal pad with variable BHP for a targeted well in the pad and different initial production durations for the offset well. From the constant BHP condition and Laplace transforms, we obtained multi-MFHW solutions for transient flow. We used superposition of various constant BHP solutions to study interference among various fractures and MFHWs. The variable BHP of the targeted well is achieved by a variable dimensionless BHP function in the Laplace domain without any convolution or deconvolution calculations. A systematic validation for the proposed method is conducted using a commercial numerical simulator for cases of different initial production times for offset MFHWs, multi-MFHWs with variable BHP. Through the total material balance of the multi-MFHW system, we can analyze a target well in the pad with this multi-MFHW analysis. Interference by offset wells often appears after pseudo-radial flow in the target well's hydraulic fracture. It causes the pressure derivative curve during elliptical and infinite-acting radial flow (IARF) to rise, as does the RNP derivative. The inverse semi-log derivative has the opposite trend. Well interference also makes the rate/pressure drop functions to deviate from initial straight lines in later stages. Sensitivity analysis of well spacing shows that "transition flow" will change from elliptical to formation linear flow between wells as well spacing increases and it can show the transitional flow characteristics in more common cases.
- North America > United States > Texas (1.00)
- Asia > Middle East (0.68)
- Europe (0.68)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (26 more...)
Abstract This paper provides the theoretical and practical basis for application of multi-segment Arps production decline models, particularly for multi-fractured horizontal wells used to develop ultra-low permeability resources. Two- and three-segment Arps models have been used in the industry for production forecasting, but the application is usually based on empirical observations and intuitive assumptions. This paper provides the basis for dividing production history of these wells into at least four segments. We first examined rigorous solutions to governing flow equations for idealized conditions and found the basis to expect (1) early transient linear flow with b ≡ 2; (2) a transition flow regime between transient and boundary-dominated flow (BDF) regimes with continuously changing b about one log-cycle in duration; and (3) BDF with b ≡ 0 for an incompressible fluid. We examined the basis for the Fetkovich type curve, which include BDF stems for compressible fluids with b values ranging from 0 to 1, and found evidence that, under most circumstances, b values should range from 0.4 to 0.5 for gas wells and 0.3 to 0.4 for depletion-drive oil wells. Durations of these flow regimes can be identified using log-log plots of pressure-normalized rate vs. time (preferable) or simply rate vs. time when pressure data are not available. Analysis of the Arps hyperbolic decline model indicates that straight lines with slopes = 1/b are expected during times with unchanging b. We found that, for multi-fractured horizontal wells, at least four distinct flow regimes should ultimately appear in practice and are related to depth-of-investigation considerations: (1) an early ramp-up in production; (2) a transient flow regime which can last for years with essentially constant b, often near 2; (3) a transition flow regime, lasting for over a log cycle in time and with continuously changing b; and (4) BDF, with essentially constant b, and 0.3 < b < 0.5 in most cases. Additional segments may arise because of changed operational conditions or flow into the stimulated reservoir volume (SRV) from the unstimulated matrix. There is no reason to expect a terminal b of zero except for the rare case of an incompressible fluid. For forecasting production from wells in resource plays, we should include the minimum of four flow regimes, even when only transient flow has been observed in history, and we should forecast appropriate durations of flow regimes and times at which they expected to begin and end based on considerations discussed in the paper. These considerations are fundamentally important for forecasting of individual wells and for construction of typical well production profiles (TWPs, akatype wells or type curves).
Spacing Classification System Delivers Enhanced Confidence in Modeling Unconventional Resource Plays
Valdez, Stan (VSO Petroleum Consultants) | Quigley, Rob (VSO Petroleum Consultants) | Najvar, Tori (VSO Petroleum Consultants) | Beckendorf, Austin (VSO Petroleum Consultants) | Taberner, Adam (VSO Petroleum Consultants) | Skrobarczyk, Louis (VSO Petroleum Consultants) | Olsen, Grant (VSO Petroleum Consultants) | Lee, John (Texas A&M University)
Abstract Inter-well spacing and Parent/Child interactions in unconventional resource plays have become an increasingly publicized issue in the oil and gas industry and several recent, wide-spread reports have amplified concerns regarding the impact of these factors on well performance and remaining drilling inventory. However, the industry lacks common standards and definitions regarding these issues. The purpose of this paper is to provide a rigorous framework for classifying and analyzing spatial and temporal relationships between existing and future horizontal wells. This will in turn help operators and investors to systematically assess and optimize asset development. We first introduce a discussion of recent literature related to inter-well spacing and Parent/Child interactions, and the key reservoir properties and completion variables which influence these interactions. Next, we present our Spacing Classification System ("SCS") along with several illustrative examples of how to apply this system. Lastly, we explore four case studies in the Williston Basin and discuss the observations in each study. The approach to classifying existing and future wells in terms of distance and timing relative to offset wells is straightforward and unique. When applied to Williston Basin rate-time data, the system clearly and compellingly illustrates the severity of well spacing and timing on horizontal wells for the 6 different SCS well configuration scenarios. When employing our system and generating development plans, optimized spacing will ultimately be a function of objectives which are specific to each operator or investor. This work offers evaluators with improved insight into the productivity of unconventional plays as a function of inter-well spacing and enables improved accuracy in forecasting both well behavior and development economics. The SCS can provide guidance which can be used to choose analogous wells more rigorously for the purpose of building Type Well Profiles ("TWP") which better represent future performance. The methodology may afford operators and investors the opportunity to re-calibrate certain expectations regarding remaining inventory and pace of development.
- North America > United States > Texas (1.00)
- North America > United States > North Dakota (1.00)
- Geology > Petroleum Play Type > Unconventional Play (1.00)
- Geology > Geological Subdiscipline (0.93)
Abstract This paper proposes the difference-value plotting function (DVPF) for the diagnostic analysis and interpretation of pressure transient test data in low-permeability reservoirs. Specifically, this work uses the approximation of the analytical solution for the performance of a vertical well with a single finite conductivity vertical fracture, where a Taylor Series expansion is used to obtain an asymptotic solution for early-time flow, which includes terms for wellbore storage and fracture conductivity. The well-testing derivative of this result is then obtained and is of a similar form. By subtracting the derivative form from the pressure form, we remove the "dominant" wellbore storage term from the asymptotic solution. We then need to normalize that difference by the square root of time (or dimensionless time) to obtain the final formulation of the DVPF which leaves a single constant parameter multiplied by time on the right-hand-side. Our contention is that this formulation leaves us with a diagnostic plotting function which provides a unique and contrasting behavior compared to using the pressure drop and/or pressure drop derivative functions alone for diagnostics and interpretations. As is typical of pressure transient or well testing data at early times, the observed pressures often exhibit random data noise. As such, we have adapted a noise reduction algorithm that was originally used for signal processing to smooth both the pressure and derivative functions. Lastly, we demonstrate the difference-value plotting function (DVPF) on several cases of synthetic and field-derived data to illustrate the utility of this methodology. Specifically, we have applied this method to cases in which it is difficult to determine unique interpretations using traditional methods (e.g., insufficient duration tests, lengthy WBS distortion, and effects of ultra-low permeability). The proposed DVPF allows us to observe underlying characteristics that are obscured at early times in traditional pressure and derivative analysis, and for the demonstration examples provided in this work, the DVPF does provide a strong auxiliary means of interpretation.
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Information Technology > Artificial Intelligence > Vision (0.54)
- Information Technology > Data Science > Data Mining (0.34)
Summary In this paper, we present methodology to quantify biases in reserves estimates using technical revisions (TRs) listed in reserves‐reconciliation reports filed with regulators in the US and Canada. Using this methodology, we assessed the reliability of reserves estimates for 34 companies filing in Canada and 32 companies filing in the US from 2007 to 2017. Filers in both Canada and the US overestimated proved (1P) reserves, and US filers overestimated 1P reserves (51% positive TRs instead of 90%) more often than Canadian filers (72% positive TRs). Canadian filers underestimated proved‐plus‐probable (2P) reserves slightly (54% positive TRs instead of 50%). Considering the entire reserves distribution, Canadian filers were moderately overconfident (underestimated uncertainty) and slightly pessimistic. US filers, who report only 1P, were somewhere between the combination of extreme overconfidence and neutral directional bias (DB) and the combination of moderate overconfidence and extreme optimism. Three groups of professionals can benefit from this study: estimators, who can use the methodology to track their TRs over time, calibrate them, and use this information to improve future estimation procedures; investors, who can analyze reported reserves estimates to compare volumes fairly; and regulators, to whom the paper provides quantitative methodology to suggest to filers to help them ensure compliance with appropriate criteria for 1P and 2P reserves and avoid significant reserves write‐downs later.
- North America > Canada (1.00)
- North America > United States > Texas (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.46)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (26 more...)