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Chen, Zeliang (Rice University) | Wang, Xinglin (Rice University) | Jian, Guoqing (Rice University) | Zhang, Leilei (Rice University) | Dong, Pengfei (Rice University) | Singer, Philip (Rice University) | Hirasaki, George (Rice University)
Abstract Unconventional resources are of great importance in the global energy supply. However, the ultralow permeability, which is an indicator of the producibility, makes the unconventional production challenging. Therefore, the permeability is one of the critical petrophysical properties for formation evaluation, along with the rock porosity and compressibility. There are many existing approaches to determine permeability in the laboratory using core analysis. The methods can be divided into two categories: steady-state and unsteady-state approaches. The steady-state approach is a direct measurement using Darcy's law. This approach suffers from the accuracy in the measurement of low flow-rate and the long run-time. The unsteady-state approach includes pulse decay, oscillating pressure, and GRI methods. These approaches are complicated in terms of set-ups and interpretations. Both steady-state and unsteady-state approaches typically have a constraint on the maximum differential pressure. We propose a novel unsteady-state method to determine the permeability by transient-pressure history matching. On the experimental side, the ultralow-permeability core undergoes 1-D CO2-flooding experiments, during which the transient pressure is monitored for history matching. Another two rock properties that determine the transient-pressure history, namely the rock porosity and the pore-volume compressibility, are calculated based on the mass balance of CO2 at different states. On the simulation side, the transient-pressure history is simulated using real-gas pseudo pressure and table lookup to deal with the non-linearity in fluid properties. The free parameter, permeability, in the simulation is adjusted for history matching to determine the rock permeability. Our simulation can generate high-quality transient-pressure history with the capability of handling the non-linearity and singularity in fluid properties. Our new unsteady-state method is validated by the standard steady-state method. The advantages of this unsteady-state approach are: 1) it can be implemented with simple set-ups; 2) it can be finished within a considerably short-time period; 3) the data interpretation is straightforward; 4) it can be implemented over broad pressure ranges, even with phase transitions of the permeating fluids, not limited to CO2. This approach is a valuable addition to existing permeability measurement methods.
Abstract The paper presents the results of a multiparametric analysis of the helium saturation zone after its injection into a porous gas reservoir, the dynamics of its content in a withdrawn gas mixture and the helium recovery factor (target parameters). The calculations are performed on a three-dimensional composite hydrodynamic sector model of a homogeneous anisotropic reservoir of a virtual gas deposit. Based on the results obtained, the geological and technological factors are ranked according to the absolute value of the change of target parameters when the input parameters change. The dynamics of the influence of geological and technological factors on the target parameters is described concerning different withdrawn gas volume from the initial reserves. The identified relationships can be useful for planning of the experimental helium injection and the placement of exploitation wells at underground helium storage.
Ghaderi, S. M. (University of Calgary) | Clarkson, C. R. (University of Calgary) | Ghanizadeh, A.. (University of Calgary) | Barry, K.. (Crescent Point Energy Corp.) | Fiorentino, R.. (Crescent Point Energy Corp.)
Abstract Conventional oil production has occurred from the Bakken Formation in Saskatchewan since the mid-1950s. However, with successful implementation of multi-fractured horizontal well (MFHW) technology, the low-permeability (unconventional) Bakken has experienced ever increasing E&P activity on both sides of the US/Canada border. Prior to 2005, the Bakken in Saskatchewan had less than 100 active producers in the region but has increased to more than 2,500 producing wells since then (Sekar, 2015). Although improvement in hydraulic fracture properties and infill drilling remain the focus of recovery enhancement from the Bakken, low oil recoveries and steep initial oil decline rates are experienced using primary recovery operations, even after application of MFHW technology. Therefore, many pilots have been executed to determine the viability of waterflooding for maintaining oil rates and improving recoveries through reservoir pressure maintenance and sweep efficiency enhancement. This paper presents the performance results from one of the waterflood pilots in the Viewfield Bakken. MFHWs were used as both injectors and producers for this pilot. Five years of production/injection volumes for these wells, along with pressure data, were matched using a black-oil simulator. The calibrated model was then used to predict the long-term performance of the pilot. Finally, this model was used for further investigation of parameters affecting the performance of the waterflood operation along with assessment of EOR (gas injection) schemes applicable to the Bakken Formation. Two important conclusions can be derived from this study: 1) waterflooding can be effective in tight oil reservoirs using MFHWs as injectors and producers and, 2) careful characterization of vertical changes in reservoir quality using laboratory-based measurements are important for improving the quality of the history match and resulting forecast scenarios. For 2), permeability heterogeneity was quantified using profile permeability measurements corrected to ‘in-situ’ stress conditions.
Summary Low recovery factors in ultratight unconventional reservoirs such as the Bakken provide both a challenge and an opportunity for depletion optimization. However, meaningful improvements can only be realized with a fundamental understanding of reservoir heterogeneity and rock properties such as porosity, saturation, permeability, and wettability. Although the laboratory methods used to measure these properties are considered mature for conventional reservoirs, the multiscale complexity and heterogeneity of unconventional reservoirs pushes the limits of conventional methods, necessitating development and application of advanced laboratory and petrophysical methods. This paper presents an integrated characterization of the Middle Bakken reservoir. A variety of approaches were used to measure permeability from core plug samples, including air permeability, Klinkenberg permeability, steady-state and unsteady-state liquid permeability, and MICP derived permeability. The results of these studies show that an integrated approach, using a combination of measurement methods, can enable quantification of matrix permeability with reasonable certainty, Wettability and fluid distribution are also key unconventional reservoir parameters. An approach coupling a porosity/saturation mapping technique with mineralogy mapping at the pore scale has the potential to shed light on the intrinsic wetting behavior of the reservoir as a function of mineralogy. The last portion of this characterization study examines rock typing using high-resolution imaging techniques. Three key rock types identified in the Middle Bakken provide a framework for mapping reservoir heterogeneity and a basis for generating upscaled models which can enable future optimization of the field development.
Abstract A close coupling of geoscience and engineering disciplines has generated a history-matched model for the Dukhan Arab C reservoir serving as a platform for testing of forward development strategies. The Arab C reservoir is a heterogeneous organization of limestone and dolomite lithologies deposited on a shallow water Jurassic ramp system. Hydraulically, the 80ft thick interval represents a network of grainstone conductors compartmentalized by muddy carbonate baffles resulting in layer-constrained dynamic behavior. The reservoir has been under development for over sixty years, with an early period of natural depletion followed by peripheral water injection utilizing hundreds of vertical and horizontal producers and injectors. As part of an effort to update the field development plan, a new geologic model was developed that formed the basis for reservoir simulation studies and depletion planning. Initially, a series of tests were conducted to determine the sensitivity of model responses to input variables, and these tests helped to guide subsequent static model adjustments. Horizontal permeability defines aquifer response, waterflood front advance and early pressure trend, while vertical permeability significantly controls subsequent dynamic behavior. Thin mudstone baffles are common at parasequence boundaries and their continuity and association with stylolites determines inter-zonal vertical communication. Variable salinity of injected water was shown to have a large impact on water encroachment patterns and derivation of appropriate relative permeability functions improved the calibration of the full-field dynamic reservoir simulation model. Knowledge of the controlling parameters ranked according to dynamic sensitivity facilitated an emphasis on regional variations constrained by geological trends and helped to minimize the requirement for localized adjustments. Lessons learned as a result of this geoscience-engineering feedback can expedite future model building by focusing technical expertise on the most critical parameters controlling fluid flow. Introduction The Qatar Petroleum-operated Dukhan Field is located onshore Qatar, approximately 80km west of Doha (Figure1). The Arab C reservoir interval is a carbonate anticlinal structure lying 5500–7000ft below the surface and is approximately 70km long by 8km wide. The Arab C interval is about 80ft thick with moderate to high reservoir quality (typically 18% porosity, 100mD permeability). A high degree of vertical heterogeneity relates to a sedimentary origin in a near-shore shallow ramp environment featuring high-order depositional cyclicity. Lateral ranges of 1–4km for baffling thin-beds supports a localized layer-constrained dynamic behavior, though communication pathways are impacted by sporadic occurrences of cross-cutting conductive and resistive faults. Arab C production development began in 1949 with a period of natural depletion followed by conversion to water drive in the 1960s via peripheral water injection utilizing hundreds of vertical and horizontal producers and injectors.
Abstract Estimating basic properties of unconventional shale reservoirs—such as permeability and porosity—is critical for reservoir evaluation, formation damage prediction, hydraulic fracture design, and performance forecasting. Several techniques can be used to measure these properties. For instance, the Gas Research Institute (Luffel et al. 1993) uses crushed rock, modeling high-resolution images of micron-sized samples, pulse decay, steady-state techniques to evaluate the permeability, and gas expansion and mercury immersion for porosity of a shale sample. However, the accuracy and reliability of these techniques are not well-established for unconventional reservoir rocks because of concerns about the flow regime, the absence of net confining stress, the sample size, and the imaging technique resolution. This paper presents the results of a round robin permeability and porosity measurement performed at several commercial and research laboratories. The permeabilities of the evaluated samples vary from 10 nanodarcy to 10 microdarcy, and their porosities vary from 5 to 10%. A wide range of natural and synthetic material was computed tomography (CT) scanned and microscopically examined. Selected samples were used based on their suitability for the desired range of porosity and permeability. The samples were examined before and after drying in a vacuum oven and then tested under several stress cycles. Gas permeability was measured by use of steady-state, transient pulse decay techniques and derived from mercury injection data. Porosity was measured by use of the gas expansion technique and mercury immersion. Image analysis of focused ion beam-scanning electron microscope (FIB-SEM) was also used to model permeability. Klinkenberg permeability was derived from apparent permeability by use of a range of mean pressures to examine validity of the Darcy flow regime. The results of the round robin testing of porosity and permeability indicate: Darcy flow is the predominant flow regime in shales with permeability as low as 10 nano-darcy, based on Klinkenberg characteristics and flow rate-pressure drop criteria. Permeability measurement on 10 nano-darcy to 10 micro-darcy permeability core plugs, under 400 to 5000 psi, is feasible and repeatable with a reasonable uncertainty range, at qualified commercial laboratories. Porosity data showed uncertainties in the range of ±1.0 p.u. for the natural samples. Steady-state method provides similar results from different laboratories, as long as an identical procedure is implemented. Uncertainty in steady-state permeability data from different laboratories could be as high as ±150%. Liquid permeability testing by use of supercritical fluid or laboratory fluid (Decalin) provides a complementary and valuable piece of datum. Rotary sidewall core plugs may provide higher quality core standards for shale material testing because the core plugging takes place under reservoir temperature and stress conditions.