Browsing by Subject "Shale Gas"

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A New Series of Rate Decline Relations Based on the Diagnosis of Rate-Time Data
(2010-01-14) Boulis, Anastasios
The so-called "Arps" rate decline relations are by far the most widely used tool for assessing oil and gas reserves from rate performance. These relations (i.e., the exponential and hyperbolic decline relations) are empirical where the starting point for their derivation is given by the definitions of the "loss ratio" and the "derivative of the loss ratio", where the "loss ratio" is the ratio of rate data to derivative of rate data, and the "derivative of the loss ratio" is the "b-parameter" as defined by Arps [1945]. The primary goal of this work is the interpretation of the b-parameter continuously over time and thus the better understanding of its character. As is shown below we propose "monotonically decreasing functional forms" for the characterization of the b-parameter, in addition to the exponential and hyperbolic rate decline relations, where the b-parameter is assumed to be zero and constant, respectively. The proposed equations are as follow: b(t)=constant (Arps' hyperbolic rate-decline relation), []tbbtb10exp)(-bt= (exponential function), (power-law function), 10)(btbtb=)/(1)(10tbbtb+= (rational function). The corresponding rate decline relation for each case is obtained by solving the differential equation associated with the selected functional for the b-parameter. The next step of this procedure is to test and validate each of the rate decline relations by applying them to various numerical simulation cases (for gas), as well as for field data cases obtained from tight/shale gas reservoirs. Our results indicate that b-parameter is never constant but it changes continuously with time. The ultimate objective of this work is to establish each model as a potential analysis/diagnostic relation. Most of the proposed models yield more realistic estimations of gas reserves in comparison to the traditional Arps' rate decline relations (i.e., the hyperbolic decline) where the reserves estimates are inconsistent and over-estimated. As an example, the rational b-parameter model seems to be the most accurate model in terms of representing the character of rate data; and therefore, should yield more realistic reserves estimates. Illustrative examples are provided for better understanding of each b-parameter rate decline model. The proposed family of rate decline relations was based on the character of the b-parameter computed from the rate-time data and they can be applied to a wide range of data sets, as dictated by the character of rate data.
A Triple-Porosity Model for Fractured Horizontal Wells
(2010-10-12) Alahmadi, Hasan Ali H.
Fractured reservoirs have been traditionally idealized using dual-porosity models. In these models, all matrix and fractures systems have identical properties. However, it is not uncommon for naturally fractured reservoirs to have orthogonal fractures with different properties. In addition, for hydraulically fractured reservoirs that have preexisting natural fractures such as shale gas reservoirs, it is almost certain that these types of fractures are present. Therefore, a triple-porosity (dual-fracture) model is developed in this work for characterizing fractured reservoirs with different fractures properties. The model consists of three contiguous porous media: the matrix, less permeable micro-fractures and more permeable macro-fractures. Only the macro-fractures produce to the well while they are fed by the micro-fractures only. Consequently, the matrix feeds the micro-fractures only. Therefore, the flow is sequential from one medium to the other. Four sub-models are derived based on the interporosity flow assumption between adjacent media, i.e., pseudosteady state or transient flow assumption. These are fully transient flow model (Model 1), fully pseudosteady state flow model (Model 4) and two mixed flow models (Model 2 and 3). The solutions were mainly derived for linear flow which makes this model the first triple-porosity model for linear reservoirs. In addition, the Laplace domain solutions are also new and have not been presented in the literature before in this form. Model 1 is used to analyze fractured shale gas horizontal wells. Non-linear regression using least absolute value method is used to match field data, mainly gas rate. Once a match is achieved, the well model is completely described. Consequently, original gas in place (OGIP) can be estimated and well future performance can be forecasted.
Assessment of Eagle Ford Shale Oil and Gas Resources
(2013-07-30) Gong, Xinglai
The Eagle Ford play in south Texas is currently one of the hottest plays in the United States. In 2012, the average Eagle Ford rig count (269 rigs) was 15% of the total US rig count. Assessment of the oil and gas resources and their associated uncertainties in the early stages is critical for optimal development. The objectives of my research were to develop a probabilistic methodology that can reliably quantify the reserves and resources uncertainties in unconventional oil and gas plays, and to assess Eagle Ford shale oil and gas reserves, contingent resources, and prospective resources. I first developed a Bayesian methodology to generate probabilistic decline curves using Markov Chain Monte Carlo (MCMC) that can quantify the reserves and resources uncertainties in unconventional oil and gas plays. I then divided the Eagle Ford play from the Sligo Shelf Margin to the San Macros Arch into 8 different production regions based on fluid type, performance and geology. I used a combination of the Duong model switching to the Arps model with b = 0.3 at the minimum decline rate to model the linear flow to boundary-dominated flow behavior often observed in shale plays. Cumulative production after 20 years predicted from Monte Carlo simulation combined with reservoir simulation was used as prior information in the Bayesian decline-curve methodology. Probabilistic type decline curves for oil and gas were then generated for all production regions. The wells were aggregated probabilistically within each production region and arithmetically between production regions. The total oil reserves and resources range from a P_(90) of 5.3 to P_(10) of 28.7 billion barrels of oil (BBO), with a P_(50) of 11.7 BBO; the total gas reserves and resources range from a P_(90) of 53.4 to P_(10) of 313.5 trillion cubic feet (TCF), with a P_(50) of 121.7 TCF. These reserves and resources estimates are much higher than the U.S. Energy Information Administration?s 2011 recoverable resource estimates of 3.35 BBO and 21 TCF. The results of this study provide a critical update on the reserves and resources estimates and their associated uncertainties for the Eagle Ford shale formation of South Texas.
Effective fracture geometry obtained with large water sand ratio
(2009-05-15) Kumar, Amrendra
Shale gas formation exhibits some unusual reservoir characteristics: nano-darcy matrix permeability, presence of natural fractures and gas storage on the matrix surface that makes it unique in many ways. It?s difficult to design an optimum fracture treatment for such formation and even more difficult is to describe production behavior using a reservoir model. So far homogeneous, two wing fracture, and natural fracture models have been used for this purpose without much success. Micro seismic mapping technique is used to measure the fracture propagation in real time. This measurement in naturally fractured shale formation suggests a growth of fracture network instead of a traditional two wing fractures. There is an industry wise consensus that fracture network plays an important role in determining the well productivity of such formations. A well with high density of fracture networks supposed to have better productivity. Shale formations have also exhibited production pattern which is very different from conventional or tight gas reservoir. Initial flow period is marked by steep decline in production while the late time production exhibits a slow decline. One of the arguments put for this behavior is linear flow from a bi-wing fractured well at early time and contribution of adsorbed gas in production at late time. However, bi-wing fracture geometry is not supported by the micro-seismic observation. A realistic model should include both the fracture network and adsorbed gas property. In this research we have proposed a new Power Law Permability model to simulate fluid flow from hydraulically fractured Shale formation. This model was first described by Valko & Fnu (2002) and used for analyzing acid treatment jobs. The key idea of this model is to use a power law permeability function that varies with the radial distance from well bore. Scaling exponent of this power law function has been named power law index. The permeability function has also been termed as secondary permeability. This work introduces the method of Laplace solution to solve the problem of transient and pseudo steady-state flow in a fracture network. Development and validation of this method and its extension to predict the pressure (and production) behaviour of fracture network were made using a novel technic. Pressure solution was then combined with material balance through productivity index to make production forecast. Reservoir rock volume affected by the fracture stimulation treatment that contributes in the production is called effective stimulated volume. This represents the extent of fracture network in this case. Barnett shale formation is a naturally fractured shale reservoir in Fort Worth basin. Several production wells from this formation was analysed using Power Law Model and it was found that wells productivity are highly dependent on stimulated volume. Apparently the wells flow under pseudo steady state for most part of their producing life and the effect of boundary on production is evident in as soon as one months of production. Due to short period of transient flow production from Barnett formations is expected to be largely independent of the relative distribution of permeability and highly dependent on the stimulated area and induced secondary permeability. However, an indirect relationship between permeability distribution and production rate is observed. A well with low power law index shows a better (more even) secondary permeability distribution in spatial direction, larger stimulated volume and better production. A comparative analysis between the new model and traditional fracture model was made. It was found that both models can be used successfully for history matching and production forecasting from hydraulically fractured shale gas formation.
Fast Marching Method with Multiphase Flow and Compositional Effects
(2014-08-06) Fujita, Yusuke
In current petroleum industry, there is a lack of effective reservoir simulators for modeling shale and tight sand reservoirs. An unconventional resource modeling requires an accurate flow characterization of complex transport mechanisms caused by the interactions among fractures, inorganic matrices, and organic rocks. Pore size in shale and tight sand reservoirs typically ranges in nanometers, which results in ultralow permeability (nanodarcies) and a high capillary pressure in the confined space. In such extremely low permeability reservoirs, adsorption/desorption and diffusive flow processes play important roles for a fluid flow behavior in addition to heterogeneity-driven convective flow. In this study, the concept of ?Diffusive Time of Flight? (DTOF) is generalized for multiphase and multicomponent flow problems on the basis of the asymptotic theory. The proposed approach consists of two decoupled steps ? (1) calculation of well drainage volumes along a propagating ?peak? pressure front, and (2) numerical simulation based on the transformed 1-D coordinates. Geological heterogeneities distributed in 3-D space are integrated by tracking the propagation of ?peak? pressure front using a ?Fast Marching Method? (FMM), and subsequently, the drainage volumes are evaluated along the outwardly propagation contours. A DTOF-based numerical simulation is performed by treating a series of the DTOF as a spatial coordinate. This approach is analogous to streamline simulation, whereby a multidimensional simulation is transformed into 1-D coordinates resulting in substantial savings in computational time, thus allowing for high resolution simulation. However, instead of using a convective time of flight (CTOF), a diffusive time of flight is introduced in the modeling of a pressure front propagation. The overall workflow, which consist of the FMM and numerical simulation, is described in detail for single-phase, two-phase, blackoil, and compositional cases. The model validation is firstly performed on single-porosity systems with and without geological heterogeneity, then extended to multi-continuum domains including dual-porosity fractured reservoir and triple-continuum system. The large-scale unconventional models are finally demonstrated in consideration of the permeability correction for shale gas system and capillarity incorporation for confined phase behavior in multiphase shale oil system.
Investigation of Created Fracture Geometry through Hydraulic Fracture Treatment Analysis
(2012-11-30) Ahmed, Ibraheem 1987-
Successful development of shale gas reservoirs is highly dependent on hydraulic fracture treatments. Many questions remain in regards to the geometry of the created fractures. Production data analysis from some shale gas wells quantifies a much smaller stimulated pore volume than what would be expected from microseismic evidence and reports of fracturing fluids reaching distant wells. In addition, claims that hydraulic fracturing may open or reopen a network of natural fractures is of particular interest. This study examines hydraulic fracturing of shale gas formations with specific interest in fracture geometry. Several field cases are analyzed using microseismic analysis as well as net pressure analysis of the fracture treatment. Fracture half lengths implied by microseismic events for some of the stages are several thousand feet in length. The resulting dimensions from microseismic analysis are used for calibration of the treatment model. The fracture profile showing created and propped fracture geometry illustrates that it is not possible to reach the full fracture geometry implied by microseismic given the finite amount of fluid and proppant that was pumped. The model does show however that the created geometry appears to be much larger than half the well spacing. From a productivity standpoint, the fracture will not drain a volume more than that contained in half of the well spacing. This suggests that for the case of closely spaced wells, the treatment size should be reduced to a maximum of half the well spacing. This study will provide a framework for understanding hydraulic fracture treatments in shale formations. In addition, the results from this study can be used to optimize hydraulic fracture treatment design. Excessively large treatments may represent a less than optimal approach for developing these resources.
Minimizing Water Production from Unconventional Gas Wells Using a Novel Environmentally Benign Polymer Gel System
(2012-02-14) Gakhar, Kush
Excess water production is a major economic and environmental problem for the oil and gas industry. The cost of processing excess water runs into billions of dollars. Polymer gel technology has been successfully used in controlling water influx without damaging hydrocarbon production in conventional naturally fractured or hydraulically fractured reservoirs. However, there has been no systematic investigation on effectiveness and placement conditions of polymer gels for shutting off water flow from fractures with narrow apertures in shale and tight gas reservoirs. The existing polymer gels, like those based on Chromium(III) Acetate, as a crosslinker will exert very high extrusion pressure to effectively penetrate the narrow aperture fractures present in shale and tight gas reservoirs. This gives rise to a need for a new polymer gel system that can be used for selectively shutting off water flow from narrow aperture fractures in shale and tight gas reservoirs. The new gel system will have a longer gelation time than the existing polymer gels; this ensures minimum crosslinking of the gel by the time it reaches bottom hole. The gelant solution will be pumped at low pressure so that, it penetrates only pre-existing fractures in the formation with ease. This study for the first time focuses on developing an environmentally benign polymer gel system based on high molecular weight HPAM, as a base polymer and a commercial grade PEI as an organic crosslinker. Gel samples of different concentration ratios of the polymer and crosslinker were prepared and classified under Sydansk code of gel strength to find optimum concentration ratios that gave good gels. The gel system was characterized using Brookfield DV-III Ultra Rheometer and Fann-35 Viscometer.
Pressure Transient Analysis and Production Analysis for New Albany Shale Gas Wells
(2010-10-12) Song, Bo
Shale gas has become increasingly important to United States energy supply. During recent decades, the mechanisms of shale gas storage and transport were gradually recognized. Gas desorption was also realized and quantitatively described. Models and approaches special for estimating rate decline and recovery of shale gas wells were developed. As the strategy of the horizontal well with multiple transverse fractures (MTFHW) was discovered and its significance to economic shale gas production was understood, rate decline and pressure transient analysis models for this type of well were developed to reveal the well behavior. In this thesis, we considered a ?Triple-porosity/Dual-permeability? model and performed sensitivity studies to understand long term pressure drawdown behavior of MTFHWs. A key observation from this study is that the early linear flow regime before interfracture interference gives a relationship between summed fracture half-length and permeability, from which we can estimate either when the other is known. We studied the impact of gas desorption on the time when the pressure perturbation caused by production from adjacent transference fractures (fracture interference time) and programmed an empirical method to calculate a time shift that can be used to qualify the gas desorption impact on long term production behavior. We focused on the field case Well A in New Albany Shale. We estimated the EUR for 33 wells, including Well A, using an existing analysis approach. We applied a unified BU-RNP method to process the one-year production/pressure transient data and performed PTA to the resulting virtual constant-rate pressure drawdown. Production analysis was performed meanwhile. Diagnosis plots for PTA and RNP analysis revealed that only the early linear flow regime was visible in the data, and permeability was estimated both from a model match and from the relationship between fracture halflength and permeability. Considering gas desorption, the fracture interference will occur only after several centuries. Based on this result, we recommend a well design strategy to increase the gas recovery factor by decreasing the facture spacing. The higher EUR of Well A compared to the vertical wells encourages drilling more MTFHWs in New Albany Shale.
Rate Transient Analysis in Shale Gas Reservoirs with Transient Linear Behavior
(2010-07-14) Bello, Rasheed O.
Many hydraulically fractured shale gas horizontal wells in the Barnett shale have been observed to exhibit transient linear behavior. This transient linear behavior is characterized by a one-half slope on a log-log plot of rate against time. This transient linear flow regime is believed to be caused by transient drainage of low permeability matrix blocks into adjoining fractures. This transient flow regime is the only flow regime available for analysis in many wells. The hydraulically fractured shale gas reservoir system was described in this work by a linear dual porosity model. This consisted of a bounded rectangular reservoir with slab matrix blocks draining into adjoining fractures and subsequently to a horizontal well in the centre. The horizontal well fully penetrates the rectangular reservoir. Convergence skin is incorporated into the linear model to account for the presence of the horizontal wellbore. Five flow regions were identified with this model. Region 1 is due to transient flow only in the fractures. Region 2 is bilinear flow and occurs when the matrix drainage begins simultaneously with the transient flow in the fractures. Region 3 is the response for a homogeneous reservoir. Region 4 is dominated by transient matrix drainage and is the transient flow regime of interest. Region 5 is the boundary dominated transient response. New working equations were developed and presented for analysis of Regions 1 to 4. No equation was presented for Region 5 as it requires a combination of material balance and productivity index equations beyond the scope of this work. It is concluded that the transient linear region observed in field data occurs in Region 4 ? drainage of the matrix. A procedure is presented for analysis. The only parameter that can be determined with available data is the matrix drainage area, Acm. It was also demonstrated in this work that the effect of skin under constant rate and constant bottomhole pressure conditions is not similar for a linear reservoir. The constant rate case is the usual parallel lines with an offset but the constant bottomhole pressure shows a gradual diminishing effect of skin. A new analytical equation was presented to describe the constant bottomhole pressure effect of skin in a linear reservoir. It was also demonstrated that different shape factor formulations (Warren and Root, Zimmerman and Kazemi) result in similar Region 4 transient linear response provided that the appropriate f(s) modifications consistent with lAc calculations are conducted. It was also demonstrated that different matrix geometry exhibit the same Region 4 transient linear response when the area-volume ratios are similar.
Sedimentary and Diagenetic Controls on Petroleum System Characteristics of the Upper Cretaceous Eagle Ford Group, South Texas
(2014-04-29) Hancock, Travis A
Early diagenetic carbonate cements can affect brittleness and total organic content in shale reservoirs. Predicting these effects could potentially improve recovery efficiency and field development costs, and decrease the environmental impact of developing the field. In this study, an X-ray fluorescence spectroscopic technique was used to test for correlations between primary depositional features, diagenetic carbonate cements, and organic content and fracture distributions in core samples from the Eagle Ford Group in McMullen County, Texas. Organic content varies significantly between diagenetic facies, with the least organic matter present in coarsely mineralized shales. This result is consistent with the hypothesis that diagenetic carbonate cementation that was early relative to compaction diluted primary organic matter. In contrast, total fracture length varies significantly between depositional facies, with the lowest total fracture length per length of core present in massive shales. Carbonate diagenesis therefore likely did not exert a significant control on the formation of the bedding-parallel fractures observed in this study; instead, laminated fabrics provided planes of weakness along which stress release fractures or hydrocarbon generation-induced fractures could develop. The suggested target reservoir facies for similar Eagle Ford wells is a finely to moderately mineralized laminated shale because of the likelihood of finding high organic content and horizontal fractures that would increase the effective rock volume in communication with primary hydraulically induced fractures.
Stretched Exponential Decline Model as a Probabilistic and Deterministic Tool for Production Forecasting and Reserve Estimation in Oil and Gas Shales
(2012-07-16) Akbarnejad Nesheli, Babak
Today everyone seems to agree that ultra-low permeability and shale reservoirs have become the potentials to transform North America's oil and gas industry to a new phase. Unfortunately, transient flow is of long duration (perhaps life of the well) in ultra-low permeability reservoirs, and traditional decline curve analysis (DCA) models can lead to significantly over-optimistic production forecasts without additional safeguards. Stretched Exponential decline model (SEDM) gives considerably more stabilized production forecast than traditional DCA models and in this work it is shown that it produces unchanging EUR forecasts after only two-three years of production data are available in selected reservoirs, notably the Barnett Shale. For an individual well, the SEDM model parameters, can be determined by the method of least squares in various ways, but the inherent nonlinear character of the least squares problem cannot be bypassed. To assure a unique solution to the parameter estimation problem, this work suggests a physics-based regularization approach, based on critical velocity concept. Applied to selected Barnett Shale gas wells, the suggested method leads to reliable and consistent EURs. To further understand the interaction of the different fracture properties on reservoir response and production decline curve behavior, a series of Discrete Fracture Network (DFN) simulations were performed. Results show that at least a 3-layer model is required to reproduce the decline behavior as captured in the published SEDM parameters for Barnett Shale. Further, DFN modeling implies a large number of parameters like fracture density and fracture length are in such a way that their effect can be compensated by the other one. The results of DFN modeling of several Barnett Shale horizontal wells, with numerous fracture stages, showed a very good agreement with the estimated SEDM model for the same wells. Estimation of P90 reserves that meet SEC criteria is required by law for all companies that raise capital in the United States. Estimation of P50 and P10 reserves that meet SPE/WPC/AAPG/SPEE Petroleum Resources Management System (PRMS) criteria is important for internal resource inventories for most companies. In this work a systematic methodology was developed to quantify the range of uncertainty in production forecast using SEDM. This methodology can be used as a probabilistic tool to quantify P90, P50, and P10 reserves and hence might provide one possible way to satisfy the various legal and technical-society-suggested criteria.

Browsing by Subject "Shale Gas"

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