Development of Shale Gas Prediction Models for Long-Term Production and Economics Based on Early Production Data in Barnett Reservoir (original) (raw)

A Critical Review of Shale Gas Production Analysis and Forecast Methods

2018

DOI: 10.21276/sjeat.2018.3.5.5 Abstract: This paper critically reviews methods applied in forecasting production of unconventional gas plays. The review focuses on methodologies suitable for shale gas plays, methodological ability to account for parameter and data uncertainty, as well as suitability for appraising undeveloped shale gas plays. The production analysis and forecast methods reviewed include empirical/decline curves, type curves and analytical/numerical methods applicable to unconventional gas production analysis and forecast. The review shows that most of the studies focus on developed shale gas plays, neither account for shale gas well reservoir heterogeneity nor account for below ground uncertainties-such as reservoir and source rock properties. This study concludes that significant research is needed to address the identified limitations of existing studies.

Shale gas production decline trend over time in the Barnett Shale

Journal of Petroleum Science and Engineering, 2018

Natural gas produced from shale formations in the United States over the past decade have altered the oil and gas industry remarkably. The Barnett shale was at the forefront of the shale gas revolution in the United States and was considered to be the highest producing natural gas field in the United States until 2012, yielding the top producer spot to the Marcellus shale. Due to the uncertainty regarding the accurate determination of Estimated Ultimate Recoverable (EUR) in shale gas reservoirs, this paper aims to assess EUR values for the Barnett shale using empirical decline curve methods like the Arp's hyperbolic, Modified Arp's hyperbolic and Doung's method. In addition, we investigated the economic viability of wells over time in the Barnett under various probabilities of success. Throughout this paper, reference is made to two key publications where a similar work was carried out for various shale plays in the United States, including the Barnett shale-though only the Arp's hyperbolic decline was employed. The dataset in this paper consisted of more horizontal wells from covering more counties within the Barnett shale compared to other similar studies. We conclude that either the Arp's hyperbolic or Doung's method can be used to forecast EUR in the Barnett shale as only marginal differences were observed. This is on the basis that production history exceeds 10 months (a maximum of 80 months production history was used). We also obtained reliable and conservative estimates of EUR compared to previous studies.

Forecasting production of liquid rich shale (LRS) reservoirs using simple models

Journal of Petroleum Science and Engineering, 2017

Due to the advent of shale reservoirs as important sources of oil and gas production, there has been a critical need for reliable techniques for forecasting production and estimating reserves from these plays. This work presents the results of a study to determine whether simple decline models can be used to forecast production and estimate reserves of both oil and gas in liquid rich shale (LRS) reservoirs with reasonable accuracy. We found that hybrid models (i.e., one model such as the Duong model for transient flow coupled with a different model, such as the Arps hyperbolic model with an appropriate value of the parameter "b") are appropriate for forecasting oil production and that it is possible to forecast solution gas production with availability of adequate data. To establish the "truth case" for comparison, we simulated production with four different reservoir fluids using a commercial compositional reservoir simulator. We tested a variety of hybrid and simple DCA models on simulated data (and later on field data) with a work flow that included identifying flow regimes with diagnostic plots for each fluid sample. We analyzed 0.5-3 years of production history to estimate model parameters for forecasting future production. Also, we forecasted gas production using a technique similar to one recently presented in the literature. Lengthy transition periods between transient linear flow and boundary dominated flow (BDF) were observed on the diagnostic plots. This is presumably due to multi-phase flow effects, as this transition period is typically much shorter in single-phase shale reservoirs. As in single-phase flow, the Arps decline model proved to be good for forecasting in the BDF regime. For transient flow, we examined the Duong model (which includes transient linear flow as a special case) and YM-SEPD (modified form of Stretched Exponential Production Decline model). In some cases, we applied the Arps model for both the transition period and BDF regimes (with different b values). We concluded that hybrid DCA models are more appropriate for multi-phase flow analysis than simple DCA models. In most of the cases, the hybrid YM-SEPD and Arps models led to more accurate oil production forecasts than other alternatives. Our analyses of solution gas forecasts indicated that solution gas production forecasting is possible but there is still need for more research in this area.

Characteristic Production Decline Patterns for Shale Gas Wells in Barnett

This paper derives characteristic decline patterns for shale gas wells by analyzing historical well production data using decline curve analysis of 14,453 shale gas wells in the Barnett shale play from 2000 to 2014. The Hyperbolic model and the Stretched Exponential model are applied on the well-by-well production data at average aggregate well and individual well levels to derive the characteristic parameters. Both the Hyperbolic curve and the Stretched Exponential curve display a good fit to the data for both the average aggregate and the individual shale gas wells. The Hyperbolic model performs slightly better than the Stretched Exponential model in this study. The first year rate of decline for production of a shale gas well is around 60% and over the first two years is around 73%. There is an increasing trend in initial production for new wells over the last decade. A supposed cutoff production rate of 133 Mcf/d results in the estimated ultimate recoverable resource (URR) of about 1.4-2.7 billion cubic feet and a well life time of 11-29 years, which is in line with other studies.

Conditioning the Estimating Ultimate Recovery of Shale Wells to Reservoir and Completion Parameters

All Days, 2016

Oil and gas production from shale has increased significantly in the United States. Forecasting production and estimating ultimate recovery (EUR) using Decline Curve Analysis (DCA) is performed routinely during development and planning. Different methods to calculate EUR have been used in the industry (Hyperbolic Decline, Power Law, Stretched Exponential, Dung's and Tail-end Exponential). Traditionally, the decline curve analysis method by Arps (1945) was considered to be the best common tool for estimating ultimate recovery (EUR) and reserves. However, the Arps' equations over estimate of reserves when they are applied to unconventional reservoirs. Multiple modifications to Arp's method have been proposed in order to extend the applicability of DCA to forecast production and estimate the recovery from shale wells. Decline Curve Analysis, including all its flavors that recently have surfaced, is essentially a curve fitting technique that does not take into account reserv...

Statistical, Data-Driven Approach to Forecasting Production from Liquid-Rich Shale Reservoirs

OALib

The oil and gas industry needs fast and simple techniques of forecasting oil and gas production. Forecasting production from unconventional, low permeability reservoirs is particularly challenging. As a contribution to the continuing efforts of finding solutions to this problem, this paper studies the use of a statistical, data-driven method of forecasting production from liquid-rich shale (LRS) reservoirs called the Principal Components Methodology (PCM). In this study, production of five different highly volatile and near-critical oil wells was simulated for 30 years with the aid of a commercial compositional simulator. Principal Components Methodology (PCM) was applied to production data from the representative wells by using Singular Value Decomposition (SVD) to calculate the principal components (PCs). These principal components were then used to forecast oil and solution gas production from the near-critical oil wells with production histories ranging from 0.5 to 2 years, and the results were compared to simulated data and the Modified Arps' decline model forecasts. Application of the PCM to field data is also included in this work. Various factors ranging from ultra-low permeability to multi-phase flow effects have plagued the mission of forecasting production from liquid rich shale reservoirs. Traditional decline curve analysis (DCA) methods have not been completely adequate for estimating production from shale reservoirs. The PCM method enables us to obtain the production decline structure that best captures the variance in the data from the representative wells considered. This technique eliminates the need for parameters like the hyperbolic decline exponents (b values) and the task of switching from one DCA model to another. Also, production forecasting can be done without necessarily using diagnostic plots. With PCM, production could be forecasted from liquid-rich shale reservoirs with reasonable certainty. This study presents an innovative and simple method of forecasting production from liquid-rich How to cite this paper: Makinde, I.

Production Patterns of Eagle Ford Shale Gas: Decline Curve Analysis Using 1084 Wells

Sustainability, 2016

This paper analyzes and quantifies characteristic production behavior using historical data from 1084 shale gas wells in the Eagle Ford shale play from 2010 to 2014. Decline curve analysis, using Hyperbolic and Stretched Exponential models, are used to derive average decline rates and other characteristic parameters for shale gas wells. Both Hyperbolic and Stretched Exponential models fit well to aggregated and individual well production data. The hyperbolic model is found to perform slightly better than the Stretched Exponential model in this study. In the Eagle Ford shale play, about 77% of wells reach the peak production of 1644-4932 mil cubic feet per day; the production decline rate of the first year is around 70%, and over the first two years it is around 80%; shale gas wells were estimated to yield estimated ultimate recoverable total resources of 1.41-2.03 billion cubic feet (20 years as life span), which is in line with other studies.

Comparison of Various Deterministic Forecasting Techniques in Shale Gas Reservoirs

Day 3 Wed, February 06, 2013, 2013

There is a huge demand in the industry to forecast production in shale gas reservoirs accurately. There are many production estimation methods including several variations of decline curve analysis (DCA), analytical simulation, and numerical simulation. Each one of these methods has its advantages and disadvantages, but only the DCA techniques can use readily available production data to forecast rapidly and, to some extent, accurately. Traditional DCA methods in use in the industry, particularly Arps’ decline model, were originally been developed for wells in boundary Dominated Flow (BDF). By contrast, in shale reservoirs, the dominant flow regime is long-duration transient flow. Therefore, the petroleum industry needed to develop newer models to match data in transient flow regimes and then for forecast production using these transient flow models, followed, in necessary, by BDF models. The Stretched Exponential model, the Duong model and the Arps model with a minimum terminal dec...

Analysis of Production Data from Horizontal Shale Wells Using Decline Curves

Recent interest in the exploitation of Marcellus shale play, using horizontal drilling and multistage hydraulic fracturing, has increased the demand for reliable estimation of recoverable reserves from ultra-low permeability shale gas formations. Due to the limited field experience, the production performances of Marcellus shale gas reservoirs as well as the key parameters that affect the long-term production of the horizontal wells have not been well-established. Among all the prediction methods, only the Decline Curve Analysis (DCA) technique has proved successful in forecasting production data rapidly and to a high degree of accuracy. Several DCA models including conventional Arps, PLE, and Duong have been utilized in this study to determine the most appropriate method for production data from horizontal Marcellus shale wells. Fekete (Fast Evolution) simulator has been used to generate the thirty year production data from 3000 feet of horizontal lateral. The two base scenarios include seven and thirteen hydraulic fracture stages. The gas adsorbed to shale is also considered. The applicability of several DCA models to shale gas production history was examined using the simulated production profiles. The impact of the permeability, fracture half length, and matrix porosity on DCA models constants were also investigated. Finally, the proposed ratio methodology was applied to the limited production profile (3.5 years of production history) from a well in Upshur County, WV to estimate the DCA constants, and predict the long-term production performance. The prediction results from DCA models then compared to the history-matched simulation model predictions for confirmation.