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Frantz, Joseph H. (Schlumberger Data & Consulting Services) | Sawyer, Walter K. (Schlumberger Data & Consulting Services) | MacDonald, Ronald James (Schlumberger Data & Consulting Services) | Williamson, Jeron Ray | Johnston, David (Schlumberger) | Waters, George (Schlumberger DCS)
Abstract This paper presents the results of using a shale-specific, finite-difference reservoir simulation model to history match and forecast production data from the Barnett Shale reservoir. The paper will illustrate the many uses of the model for vertical and horizontal wells including determining gas in place, re-covery factors, optimal well spacing, drainage areas and drainage shapes, optimal fracture half-lengths and conductivi-ties, infill evaluations, horizontal well modeling and optimal number of stimulation treatments, analysis of microseismic data, and compression evaluations. The model was developed in the early 1990s to incorporate all of the production mecha-nisms inherent in shales including matrix gas porosity, gas desorption isotherm, single- or two-phase flow of gas and wa-ter in the natural fractures, layers, complex hydraulic fractures, and variable flowing bottomhole pressures. The paper will discuss the methodology to incorporate all field data into the simulator including core, logs, well test, completion, stimula-tion, microseismic, and production data. Examples will be given using public datasets. We also show production com-parisons between vertical and horizontal wells since this is of topical interest in the play's development history. Further-more, we discuss the various types of data to collect, their importance to proper stimulation design, and the integration methodology to evaluate and complete shale reservoirs. Introduction The Barnett Shale is currently one of the most prolific gas reservoirs in the United States. Activity continues to increase with over 90 rigs drilling as shown in Fig. 1. Starting after 2000 when Devon acquired Mitchell Energy, the number of wells drilled has increased steadily. Numerous operators are actively expanding the play from its original area in Wise and Denton Counties to the north, south, and west. In addition, horizontal well drilling has opened up areas west of the Viola limestone formation. The Viola is a boundary to contain the stimulation treatment from entering the deeper, water producing Ellenburger. Fig. 2 shows the total production from the Barnett shale. Fig. 2 is not completely up to date and current production is estimated to be approximately 1.25 Bscf/D with over 3,700 producing wells. They are also currently over 300 horizontal wells producing out of the 450 drilled to date. The volume from the horizontal wells is estimated at over 300 MMscf/D. Over 80% of the vertical wells have been drilled since 2000 and greater than 97% of the horizontal wells have been drilled since 2003, thus this is a very young growth play. Since 1981, the total gas produced from the field is estimated at over 1.4 Tscf. In 2004 alone, it produced 365 Bscf making it the largest gas field in Texas.
The development of shale assets has reached a point where operators face the challenge of infill drilling. The scope of this project is to investigate the impact of neighboring well pads on the performance of a newly developed well/pad. This paper highlights the differences in production performance of "old" pads versus "new" well and analyzes how the depletion history of the existing pads affects the performance of new well.
The study area covers two pads: Pad A and Pad B which have 10 and 12 wells respectively; these wells have been producing since 2016 from the dry gas region of Marcellus Shale in southwestern Pennsylvania. Pad A and Pad B are more than 9000 ft apart, and the region between these two pads has potential for future development. For this project, a 3-D reservoir simulation model that includes both pads was built and calibrated to match past performance of Pad A and Pad B. The calibrated simulation model then was utilized for developing new wells. The reservoir simulation model was used to perform a sensitivity analysis on reservoir characteristics and the impact of Pad A and Pad B's depletion history on the performance of new well(s). The workflow involves optimizing the well spacing of proposed well(s) with/without considering the depletion history.
Usually, with the very low permeability of shale reservoirs, the depletion history of neighboring wells is expected to affect the performance of newly developed wells. The new wells are considered as a different well pad, and their stimulated reservoir volume does not overlap with the Pad A and Pad B. However, the region average reservoir pressure is reduced due to the Pad A and Pad B production history. In most of shale reservoir numeral simulation studies, the reservoir is considered virgin. The average reservoir pressure potentially impacts the well spacing optimization workflow as well as the designing of an effective well completion job. In this study we compare two scenarios. One scenario considers the depletion history of neighboring well pads and the other one does not. The net present value optimization was done with and without considering the impact of depletion history.
This project studies the effects of neighboring well pads on production performance of newly developed pad. Compared to the interaction of parent/child well in a single well pad, multi-pad studies are rare primarily because of the high computational cost associated with a multi-pad numerical simulation analysis.
Abstract The current scheme for developing shale reservoirs necessitates special considerations while estimating the reserve. While reservoir characteristics lead to an extended infinite acting flow regime, completion schemes could result in a series of linear flows. Therefore, the initial linear flow does not have to be followed by a boundary-dominated flow. Overlooking this observation leads to unphysical Arps’ exponents and overestimations of the Estimated Ultimate Recovery (EUR). We are proposing a workflow to overcome these challenges and honor the inherited uncertainty while using the classic Arps (1956) hyperbolic forecast. Our workflow starts with identifying the current flow regime of the well where two intermediate flow regimes are considered, namely Linear-post-Linear (LPL) and Linear Post Linear Post Linear (LPLPL) flow regimes. We deterministically forecasted the boundary-dominated wells and probabilistically forecasted the rest. We used the distribution of the current flow regime in the field to forecast the transient wells. The well features of the infinite/semi-infinite wells are stochastically sampled from the field database combining well features of the boundary-dominated wells. After that, Monte Carlo simulation is employed to probabilistically estimate the EUR. We constrained the well life by an economical limit or a maximum of 40 years. Bone Springs formation is selected for a field study of this workflow. We found that the LPL is the common current flow regime. A reduction in Arps’ exponent is observed when well experience an intermediate linear flow before boundary-dominated flow. Significant number of interference wells are identified through their Water/Oil Ratio (WOR) signature. We also studied the evolution of EUR which suggests that more than 75% of the production history is needed for the deterministic methods to provide reliable estimates of the EUR. We generated heat maps of the area of interest to summarize the EUR and remaining reserve results.
Iino, Atsushi (Texas A&M University) | Vyas, Aditya (Texas A&M University) | Huang, Jixiang (Texas A&M University) | Datta-Gupta, Akhil (Texas A&M University) | Fujita, Yusuke (JX Nippon Oil & Gas Exploration Corporation) | Bansal, Neha (Anadarko Petroleum Corporation) | Sankaran, Sathish (Anadarko Petroleum Corporation)
Abstract This paper demonstrates the novelty and practical feasibility of the FMM-based multi-phase simulation for rapid field-scale modeling of shale reservoirs with multi-continua heterogeneity. Modeling of unconventional reservoirs requires accurate characterization of complex flow mechanisms in multi-continua because of the interactions between reservoir rocks, microfractures and hydraulic fractures. It is also essential to account for the complicated geometry of well completion, the reservoir heterogeneity and multi-phase flow effects. Currently, such multi-phase numerical simulation for multi-continua reservoirs needs substantial computational time that hinders efficient history matching and uncertainty analysis. In this paper, we propose an efficient approach for field scale application and performance assessment of shale reservoirs using rapid multi-phase simulation with the Fast Marching Method (FMM). The key idea of the reservoir simulation using the FMM is to recast the 3-D flow equation into 1-D equation along the ‘diffusive time of flight’ (DTOF) coordinate, which embeds the 3-D spatial heterogeneity. The DTOF is a representation of the travel time of pressure propagation in the reservoir. The pressure propagation is governed by the Eikonal equation which can be solved efficiently using the FMM. The 1-D formulation leads to orders of magnitude faster computation than the 3-D finite difference simulation. The use of FMM-based simulation also enables systematic history matching and uncertainty analysis using population-based techniques that require substantial simulation runs. We first validate the accuracy and computational efficiency of the FMM-based multi-phase simulation using synthetic reservoir models and comparison with a commercial finite-difference simulator. Next, we apply our proposed approach to a field example in Texas for a multi-stage hydraulically fractured horizontal well. The 3-D heterogeneous reservoir model was built and history matched for oil, gas and water production using the Genetic Algorithm with the FMM-based flow simulation. Multiple history-matched models were obtained to examine uncertainties in the production forecast associated with respect to the properties related to hydraulic fractures, microfractures and the matrix.
Abstract In planning successful development of any field, one of the key objectives is to determine the remaining infield potential. In conventional reservoirs, this is usually performed by using decline curve reserves coupled with volumetric recovery. There exist two disparities when the same methodology is applied in ultra low permeability reservoirs such as shale formations. First, production data used in decline curve analysis may be governed by infinite acting rather than boundary dominated flow regime. The prolonged infinite acting production reduces volumetric recovery efficiency to half of what is obtained in conventional reservoirs in situations where spacing exceeds the drainage area during a life of the well. Secondly, in these tight reservoirs, hydraulic stimulation generates the necessary conduit for hydrocarbons to flow at commercial rates, and may also interconnect individual wells into a flow network. Interference among wells in the same flow network must be accounted for to accurately assess remaining infield potential. This study addresses these issues by developing a new evaluation system to assess field maturity. Production data from 40 wells of core area Barnett shale were analyzed in this study. Based on infinite acting flow behavior exhibited by these wells, new methodologies are presented to estimate reserves and recovery. These methodologies are applicable to the cases where flow over the life of a well is governed by an interconnected yet infinite acting flow system. A new reservoir management tool is presented which serves as an aid in assessing field development maturity. It is developed by utilizing a correlation between cumulative stimulation treatment volume and reserves which are adjusted for interference and restimulation. Stimulation treatment volume was selected owing to the mixed presence of vertical and horizontal wells found in the investigated reservoir - the Barnett shale. Due to the straightforward nature of this evaluation system, it can be applied to other shale or ultra tight formations as well as to conventional reservoirs.