Horizontal wells with hydraulic fractures in tight oil reservoirs show producing-gas/oil-ratio (GOR) behavior that is very different from conventional, higher-permeability reservoirs. This paper explains the reasons for the observed behavior by use of reservoir simulation, with field examples from the STACK and SCOOP plays of the Anadarko Basin in central Oklahoma.
A framework for interpreting observed GOR behavior in tight black-oil reservoirs is modeled after the following stages in a well’s history. Some stages may not be visible because of the degree of undersaturation, flowing-bottomhole-pressure schedule, finite-conductivity fractures, and duration of the transient-flow period.
Fundamental differences between linear and radial flow, which cause the dependence of GOR on flowing bottomhole pressure, are explained by use of simulation. During transient linear flow, the GOR response to changes in flowing bottomhole pressure is independent of permeability for infinite-conductivity fractures, but not for finite-conductivity fractures.
Several practical observations are made. Knowing Rsi and the transient-GOR-plateau level in an area can help one interpret where a well is in its GOR history. Rate-transient-analysis (RTA) diagnostic plots are altered by rising GOR, and sometimes show an early unit slope. During boundary-dominated flow, GOR is more a function of cumulative production than of time; wells with closer fracture spacing have a faster GOR rise with time, but also recover oil more quickly. If compound linear flow develops, GOR can decline late in the well life. The Meramec and Woodford formations in STACK can be history matched without invoking a suppressed bubblepoint caused by pore-proximity effects. The critical gas saturation in the Meramec appears to be in the range of 0–5%.
Technical contributions include a framework for interpreting GOR behavior over well life; the effect of changing bottomhole flowing pressure on GOR; the effect of fracture spacing, conductivity, and half-length on GOR; and the effect of GOR on RTA diagnostic plots.
Bhattacharya, Sayantan (University of Calgary) | Mallory, Donald G. (University of Calgary) | Moore, R. Gordon (University of Calgary) | Ursenbach, Matthew G. (University of Calgary) | Mehta, Sudarshan A. (University of Calgary)
The accelerating rate calorimeter (ARC) is unique for its versatility of operation and application--reliability, validity, and accuracy of results--caused by very-high adiabaticity. Accelerating rate calorimetry is one of the screening tests used to determine the suitability of a reservoir for air-injection enhanced oil recovery. The ARC is well-suited for investigating the reaction mechanisms in the low-temperature range (LTR), negative-temperature-gradient region (NTGR), and high-temperature range (HTR). The ARC provides full time–temperature, time–pressure, and self-heat rate inverse absolute-temperature profiles. An experimental and simulation study is carried out to expand knowledge and interpretation of the data derived from high-pressure closed ARC tests. Athabasca bitumen is used for the experimental study in a closed ARC at an initial pressure of 13.8 MPag (2,000 psig) to identify the nature of the oxidation reactions occurring over the different temperature ranges.
The simulation component of the study focused on the development of a numerical model that captured the elements of the ARC test. The model incorporated solubility of oxygen and diffusion to control the transfer of oxygen in the liquid-oil phase. Mass transfer is found to play an important role at low temperatures up to the temperature at which chemical interaction starts to control the distribution of oxygen within the liquid bitumen.
Likewise, vaporization of oil and generation of vapor by cracking reactions are also believed to play an important role in air-injection processes. Therefore, a vapor-phase combustion reaction is integrated into the traditional Belgrave kinetic model. This modified model predicted that the combustion of vaporized oil integrated with its flammable limits and the rate of diffusion of the vaporized component in the gas phase.
The results of this study indicate that, with the addition of mass transfer to the kinetic model, it is possible to predict the NTGR. The result showed that solubility and diffusion of oxygen played an important role up to a temperature of 125°C at which chemical reactions started to control the distribution of oxygen within the liquid bitumen. The results also showed that vapor phase combustion creates a temperature gradient between the gas and bitumen phases when vaporized components became flammable (stoichiometry). This showed that the ARC could be an effective tool for understanding liquid and vapor-phase reaction and their relative importance in different temperature regimes.
The choice of appraisal strategy for the decision whether to develop a reservoir largely determines the amount of uncertainty that is carried forward to the development and execution phase of the project. Hence, the selection of an appraisal strategy can indirectly influence later go/no-go decisions. Reservoirs are appraised by drilling and producing wells. In unconventional reservoirs, these wells represent a small subset of possible wells that could be monetized if the decision were made to develop the reservoir (i.e., the appraisal wells sample an underlying population of possible wells).
This study explores how an optimal appraisal strategy can be designed in terms of the number of appraisal phases, the number of wells to be drilled in each appraisal stage, and how long to produce the appraisal wells before deciding whether to abandon the project or to proceed to the next stage. It is demonstrated how the view on the average expected ultimate recovery (EUR) of a well in an unconventional reservoir can be continually revised as new information surfaces.
Production data from a large well set from the Montney Formation, which straddles British Columbia and Alberta, Canada, is used to assess how accurately initial production predicts the expected ultimate recovery of a single well.
In this text, the authors present a study on estimating the lost gas during the retrieval process of coal sample within wellbores. A new method is proposed because the traditional ones often give inaccurate predictions. To this end, the major sources of errors with those routine methods are first discussed briefly, and modifications are made accordingly in the present method to improve the accuracy of prediction. This new method takes into account these aspects: (1) Both the advection and diffusion effects are included in the proposed flow equation; (2) the present model uses the actual shape of the core sample (say, a cylinder) rather than a simplified 1D spherical object; and (3) a fully numerical scheme is developed in which the actual retrieval history is used to specify the boundary conditions of the core sample. When the relevant sorption isothermal curve for the coal is known, the proposed model contains three parameters to be determined, which refer to the effective permeability, the effective diffusion coefficient, and the initial gas content or the initial gas pressure. The three parameters are determined through best matching the experimental data with the aid of an artificial-neural-network (ANN) technique. Two application examples are presented in this study. One is with a benchmark laboratory test, and the other is with a standard field case studied by means of an established method. It is shown with the two examples that the present method can give accurate predictions for the lost gas volume concerned, and offers some important advantages that the traditional ones do not have.
The amount of information available for field-development planning is limited, forcing the production strategy (PS) to be designed with a great amount of uncertainty. During its implementation, new information allows the adaptation of the strategy for economic gain. This work reproduces the field-development process under geological uncertainty in case study UNISIM-I-D (benchmark case that is based on Namorado Field in Brazil). The main objectives are to evaluate the process and to observe the evolution of risk curves, all in a controlled environment with real-field features.
The methodology generates new geostatistical images on the basis of new well logs, assimilates production data with an ensemble-based method, and reoptimizes the PS with a hybrid algorithm. The field development is carried out by repeatedly applying this framework with human supervision. Each step is customized with algorithms to simplify the implementation and to reduce computational effort, making this methodology more appealing for practical use. New data are collected from a high-resolution reference model that does not belong to the ensemble of models. The process starts with a PS, previously optimized under the uncertainties of the case study, which yields the real economic outcome within the original uncertainty range.
Results show high-quality history matching (HM) that excessively reduced the risk range and the variability of the updated model sets. Optimizations on the PS, on the basis of the updated ensembles, consistently increased the expected monetary value (EMV) of the project without guaranteeing an increment in the real net present value (NPV). Applying the methodology repeatedly throughout the field development increased the EMV by 29% (from USD 1.532 billion to USD 1.975 billion), whereas the real NPV decreased 2% (from USD 1.346 billion to USD 1.319 billion), falling out of the expected range and revealing that the model sets did not fully represent the real field. The lack of good representation is aggravated by heterogeneities inherent to the unknown reservoir, which are difficult to identify with only well logs and production data.
The results from the application of a closed-loop reservoir development process in a controlled environment warn against similar hidden mechanisms happening on real-field developments under similar circumstances. They reveal intrinsic pitfalls in reservoir modeling that may contribute to production-forecast problems and call for a reflection on how reservoir uncertainty assessment is performed. We prove that large sets of models do not guarantee coverage of geologic uncertainties because they do not fully represent the real reservoir. The field-development process naturally changes the risk curves, contributing to revealing the lack of representation.
Shale gas is playing an important role in transforming global energy markets with increasing demands for cleaner energy in the future. One major difference in shale-gas reservoirs is that a considerable amount of gas is adsorbed. Up to 85% of the total gas within shale may be found adsorbed on clay and kerogen. How much of the adsorbed gas can be produced has a significant effect on ultimate recovery. Even with improving fracturing and horizontal-well technologies, the average gas-recovery factors in US shale plays are only approximately 30% with primary depletion. Adsorbed gas can be desorbed by lowering pressure and raising temperature and reservoir-flow capacity can be also influenced by temperature, so there is a big prize to be claimed by use of thermal-stimulation techniques to enhance recovery. To date, not much work has been done on thermal stimulation of shale-gas reservoirs.
In this study, we present general formulations to simulate gas production in fractured shale-gas reservoirs for the first time, with fully coupled thermal-hydraulic-mechanical (THM) properties. The unified-shale-gas-reservoir model developed in this study enables us to investigate multiphysics phenomena in shale-gas formations. Thermal stimulation of fractured gas reservoirs by heating propped fractures is proposed and investigated. This study provides some fundamental insight into real-gas flow in nanopore space and gas-adsorption/desorption behavior in fractured gas shales under various in-situ conditions, and sets a foundation for future research efforts in the area of enhanced recovery of shale-gas reservoirs.
We find that thermal stimulation of shale-gas reservoirs has the potential to enhance recovery significantly by enhancing the overall flow capacity and releasing adsorbed gas that cannot be recovered by primary depletion. However, the process may be hampered by the low heat transfer rate if only the surfaces of hydraulic fractures are heated.
Experimental data have shown that the solubility of water in the oleic (L) phase (xwL) can be significant at elevated temperatures. However, xwL was not properly considered in prior studies of steam-assisted gravity drainage (SAGD) and expanding-solvent (ES)-SAGD. The main objective of this research is to present a detailed study of compositional mechanisms in SAGD and ES-SAGD simulation by considering xwL.
The phase-behavior models used in this research are carefully created on the basis of experimental studies presented in the literature. Mechanistic simulation studies are then conducted for SAGD and ES-SAGD. Coinjectants used in ES-SAGD simulations range from propane through n-decane.
Results show that xwL enhances bitumen production in both SAGD and ES-SAGD, mainly because xwL results in reduction of L-phase viscosity. The enhancement is more significant when the chamber-edge temperature is higher, because xwL increases with temperature. The enhancement of bitumen production observed in the case studies is 7.66% for SAGD, 4.08% for n-C6-SAGD, and 4.85% for n-C8-SAGD for a fixed period of operation at 35 bar. It is important to consider xwL in SAGD and ES-SAGD simulations, because the performance of ES-SAGD relative to SAGD tends to be overestimated without considering xwL.
A guideline is presented to leverage xwL to improve bitumen production in ES-SAGD. As discussed in our prior research, solvent becomes effective in diluting bitumen and reducing the steam requirement only when it sufficiently accumulates near the chamber edge. New results show that water can act as a diluting agent until solvent sufficiently accumulates near the chamber edge.
Premature water breakthrough negatively affects waterfloods in low permeability, naturally fractured reservoirs such as the South Belridge Diatomite. Premature water breakthrough reduces the effectiveness of waterflooding by partially or entirely bypassing the reservoir matrix where most of the reservoir fluids are stored. Reservoir simulation is handicapped by the inability to accurately characterize the architecture of the natural and induced fractures that yield high conductivity flow paths between injectors and producers. Generally, reservoir simulation can only represent the effective fluid flow by ignoring the ineffective water production that bypasses the matrix.
Detailed production performance analysis yields a practical approach to assist reservoir simulation in history matching the waterflood process under premature water breakthrough conditions. Basic reservoir and rock–fluid characterization parameters must be tuned by history match of primary production or before water injection related effects dominate fluid flow under waterflooding. The Y-function waterflood analytical method is used to diagnose premature water breakthrough on a well-to-well basis for the timing and duration. Effective water injection and production volumes are recalculated in reservoir simulation and used to achieve a history match that honors oil production, reservoir pressure level, and injection/production volume balance. A field-scale case study is presented to demonstrate the application and procedure of the proposed approach. The long-term waterflood prediction with the history match model has been validated by comparing with analytical method forecast as well as the up-to-date continuous waterflood field data (4.5 years after history match date in the last reservoir simulation project). The proposed practical approach makes reservoir simulation a meaningful predictive tool in waterflood reservoirs when premature water breakthrough is a significant issue.
The objective of this paper is to present a methodology with drill cuttings for making estimates of porosity, permeability, and compressibility as a function of confining pressures in tight formations.
An easy-to-use stress-dependent permeability correlation is developed by comparing results from experimental work including hysteresis at various combinations of overburden and pore pressures in vertical and horizontal core plugs, and permeabilities determined in the laboratory from drill cuttings. On the other hand, stress-dependent porosity and compressibility correlations with respect to permeability as a function of net confining stress (NCS) are also introduced. The work is important because of the presence of stress-dependent slot and/or microfracture porosities and permeabilities in tight formations that can significantly affect reservoir performance and forecasting.
Recent work has shown that drill cuttings can be used quantitatively for complete petrophysical evaluation and rock-mechanical-properties estimation (Olusola and Aguilera 2013; Ortega and Aguilera 2014). The methods have been shown to be useful in those instances in which cores and specialized well logs are scarce. Porosity and permeability values obtained from the aforementioned works are extended in this paper to quantitative evaluation of stress-dependent properties.
It is concluded that drill cuttings are important direct sources of information that can be used for developing estimates of stress-dependent petrophysical properties particularly in those cases in which cores and specialized logs are scarce or not available. The methodology and stress-dependent-permeability, -porosity, and -compressibility correlations are presented in detail, as well as a practical application for the case of drill cuttings. Although the main and novel contribution is the development of easy-to-use correlations for stress-dependent tight reservoirs with drill cuttings, the correlations can obviously be used if only plug data are available.
Log-log superposition-time derivative plots are used to identify flow regimes in well tests with variable rate. The use of superposition time adjusts for the effect of the prior rate history, and (under some conditions) shows what the transient would have looked like if the test had been performed at a constant rate. In this report, I show that if these plots are used to interpret shut-in transients from diagnostic fracture-injection tests (DFITs), the superposition-time derivative has an upward deflection that does not represent actual reservoir or transient behavior. I review mathematical properties of the superposition-time derivative. I derive equations for the pressure transient in a simplified model DFIT in which closure does not occur. I show that the onset of late-time impulse flow is controlled by injection volume and formation, wellbore, and fracture properties, not the duration of injection (as implied by the definition of superposition time). Log-log superposition-time derivative plots of DFITs exhibit a slope of 3/2 at intermediate time. However, pressure change never scales with a 3/2 power of time. One form of the G-function superficially resembles a superposition-time function constructed by summing constant-rate solutions with 3/2 power scaling. However, this is not a mathematically or physically valid interpretation. The 3/2 power arises from a spatial integration of the Carter leakoff solution. There is not a mathematical, physical, or practical justification for plotting DFIT pressure-time data in a way that creates a 3/2 slope. I conclude by providing a field example and practical recommendations for DFIT interpretation.