Swami, Vivek (CGG Services Canada Inc.) | Settari, Antonin (CGG Services Canada Inc.) | Sahai, Raki (Chesapeake Energy Corp.) | Costello, Dan (Chesapeake Energy Corp.) | Mercer, Ashley (Chesapeake Energy Corp.)
Many operators have used in the past various methods to analyze and optimize the horizontal well (HW) completions in the Eagle Ford play with varied results. Typically, such methods focus on different parts of this complex problem in relative isolation and as a consequence do not utilize all available data simultaneously. This paper presents a simulation-based method for analyzing the problem in an integrated fashion by modeling the fracturing and Stimulated Reservoir Volume (SRV) creation process, followed by well cleanup and production. Consequently, all available data are used to constrain the history match (HM), resulting in a more reliable tool for optimization.
In this work, the authors developed a comprehensive integrated model of a typical Eagle Ford well in the Dimmit County. The HM process showed that injection and production scenarios must be modeled in tandem to get better insights into the flow physics rather than simulating them separately. The best accuracy is obtained when the real sequence of fracturing is modeled. It was found that only a fraction of the created fracture and SRV lengths contribute to production. Whereas fracture half-lengths of ~250 ft were generated during injection, only about ¼ of fracture and ¾ of SRV contributed. Effect of completion efficiency was also investigated. It was shown that the assumption of only 2 perforation clusters per stage is not plausible while assuming some other scenarios offers good HM and prediction very similar to uniform efficiency.
Optimization work considered several scenarios. Cases with larger cluster/stage spacing with the same pumped volume are not desirable. However, the use of double the cluster spacing gives slightly higher estimated ultimate recovery in 30 years, and could offer significant completion cost savings. Use of current injection volumes and current well spacing (500 ft) leaves significant reservoir volume undrained, which is a target for well spacing optimization. Pressure (as opposed to stress) dependent permeability functions adequately capture the permeability variation both for injection and production.
The work shows how the integrated reservoir/fracturing/geomechanics modeling can be used to optimize completions and EUR for shale wells.
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.)
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 (
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.
The most commonly used technology for development of unconventional liquid-rich and light oil reservoirs is horizontal wells combined with large multi-stage hydraulic fracture treatments. However, even with these technological advancements, primary recovery factors are generally less than 10% (
This study investigates the feasibility of enhanced oil recovery (EOR) in a prominent tight oil reservoir in North America using cyclic solvent injection (CSI, sometimes referred to as "huff-n-puff") with carbon dioxide (CO2) as the solvent. CSI is a single well process, with the solvent remaining in the vicinity of the wellbore, as flow of the solvent through the reservoir to another well is not necessary. This type of process may be attractive from a capital cost point-of-view, as large expenditures on specialized facilities, in-field pipelines and well conversions are unnecessary.
In this study, the success and profitability of huff-n-puff is evaluated for the Bakken tight oil reservoir. Knowledge gained from a parallel study (
The huff-n-puff EOR scheme was found to be successful, but only after the aforementioned operational parameters are optimized with GA. In particular, it is important to delay huff-n-puff until production rates decline and boundary-dominated flow (after fracture interference) is reached. Importantly, as with the parallel study (
The purpose of this work is to perform an improved method to optimize different CO2 Enhanced Oil Recovery (EOR) processes in unconventional liquid reservoirs, particularly in the volatile oil region of the Eagle Ford shale. Previous simulation studies of CO2 EOR in the unconventional liquid reservoirs were not done in full field-scale and were not history matched before applying CO2 EOR to the model. Without history matching step, the simulation might generate misleading results in CO2 EOR studies. The dual-porosity, structured grid model in this paper will be history-matched with actual data collected from the field to ensure the results of CO2 EOR study to be meaningful. In addition, we are implementing the simulation in the dual-porosity mode to account for the presence of natural fractures which have been observed on Eagle Ford outcrop.
First, all data will be gathered from public sources. These data include production reports, outcrop map, natural fracture, hydraulic fracture, geology, rock, and fluid. Multiple grid sizes and number of refinements for hydraulic fractures will be tested to ensure the accuracy of the simulation is preserved yet speed up computational time. Several sensitivity analyses will be conducted to investigate which parameters from the matrix system and the natural fracture system would have a significant impact on the incremental oil recovery. These parameters will be adjusted scientifically in the process of history matching to capture the primary depletion. Then, this history-matched model will be used to apply multiple CO2 EOR studies.
The history matched model suggests that matrix porosity in the volatile oil region of Eagle Ford shale might be overestimated in many previous investigations. Also, the sensitivity analyses show that the natural fracture permeability perpendicular to the direction of the horizontal well has a significant impact on oil rates in numerical simulation. Among different CO2 EOR methods tested in this research, huff-n-puff yields the most promising outcome as compared to continuous injection and WAG (Water-alternating-gas) in both oil production and economic performance in the volatile oil region of the Eagle Ford shale. In some circumstances, continuous injection method might yield great utilization efficiency but it contains high possibility of negative incremental oil recovery at the end of EOR practice due to pressure loss during CO2 injection time, incomplete miscible process between CO2 and residual oil, and viscous fingering.
Unconventional shales can include adsorbed gas, mostly calibrated in coal seams at low pressure for CH4 and CO2, whilst also including Natural Gas Liquids and condensates. For the Duvernay formation in Alberta, Canada, the Langmuir pressure can be above 3000psia/200bar, pressures where PVT issues such as dewpoint and liquid yield are important.
The adsorbed gas released first is likely to be enriched in the lighter components, so that the composition of the gas released may not be reflective of the free gas. With an increasing proportion of dry adsorbed gas being released with pressure decline, an alteration in liquid yield can occur, even above the dew point, and this change has been observed in Duvernay production data, As initial production and gas samples will likely be representative of the free gas, such that a conventional fluid sampling and PVT analysis for dewpoint may miss the impact. The objective of this paper is to present compositional simulation work that has been completed to describe this observed behavior with a Langmuir isotherm.
The Marcellus shale has been a good training ground for understanding the impact of adsorbed gas in a dry gas system. In the Marcellus, the adsorbed gas contribution ranges from 30-50%usinghigh pressure adsorption models such as BET. When you shift from dry gas into the more liquid rich phase windows, gas condensates can have a dew point pressure in the range of 4000psia. Adsorption isotherm analysis of the Duvernay have shown Langmuir pressures in the range of 3000psia, therefore the adsorbed gas will become active as soon as the reservoir pressure drops from initial conditions.
If the adsorbed gas released is exactly the same composition as the free gas, the composition will remain unchanged, and the adsorbed gas will merely be a source of additional support, such as in the Marcellus dry gas. However, in a system with natural gas liquids and condensates, compositional effects can be anticipated, primarily with changes in the lighter ends as it is those that liberate first. In producing Duvernay wells, above the saturation pressure, changes in the C1/C2 ratio occur along with liquid yields changes appearing to indicate that the liberation of adsorbed gas in effect.
Building type wells for unconventional resource plays in early phases of development is a significant challenge for industry. Although the application of statistical techniques to type wells is gaining acceptance, it is often unclear to evaluators how these techniques can be applied to accurately capture the full range of uncertainty in the average single well estimated ultimate recovery for a geologic subset. This lack of clarity in proper methodology is especially apparent when very few analogue wells exist, or a very limited amount of production history is available. The objective of this paper is to present an integrated workflow that can be used to build P90, mean, and P10 type wells, which represent the range of potential outcomes for the geologic subset in an unconventional resource play. Through this workflow, the evaluator obtains an understanding of the key value drivers for a geologic subset and can compare and rank different geologic subsets. The proposed workflow is illustrated with an example from a North American unconventional play.
Yao, B. (Colorado School of Mines) | Wang, L. (Colorado School of Mines) | Patterson, T. (Devon Energy) | Kneafsey, T. J. (Lawrence Berkeley Laboratory) | Yin, X. (Colorado School of Mines) | Wu, Y. (Colorado School of Mines)
Cryogenic fracturing is a waterless stimulation technology that uses cryogenic fluids to fracture unconventional oil and gas reservoirs, which, to date, are rarely investigated and poorly understood. This study aims to investigate the efficacy and feasibility of cryogenic fracturing technology in enhancing the permeability of unconventional reservoir rock analogs. Laboratory cryogenic fracturing experiments and finite difference modeling are integrated to reveal the processes and mechanism of cryogenic fluids on creating fractures in synthetic rock samples.
The 8-inch cubic rock samples were initially prepared by embedding eight tiny thermocouples on their diagonals to the depth of 4 inches, so real-time temperature distribution in the samples can be monitored during the experiments. Confined with true tri-axial stresses, liquid nitrogen was injected into the borehole to crack the synthetic rock samples at low pressure (~15 psi) and reservoir temperature (~85 °C) via a tubing-casing type wellhead. Before and after the liquid nitrogen stimulation, acoustic measurements and pressure decay tests were carried out to evaluate the fracture generation and permeability enhancements of the rock samples. The experimental processes were modeled using TOUGH2-EGS by integrating the Mogi–Coulomb failure criterion into the fracture generation module.
Comparison of pre- and post-stimulation pressure decay curves showed significant permeability enhancements of the synthetic rock samples after liquid nitrogen stimulation. Delay of acoustic signal arrivals measured on rock faces indicated that multiple fractures have been created inside the rock samples. Temperature profiles recorded during the liquid nitrogen stimulation mapped the temperature distribution through the rock samples. Rock properties were measured and input into the modified TOUGH2-EGS model to simulate the experiments, the results from modeling successfully reproduced the experimental results, in terms of temperature profiles, a general fracture morphology, and pressure decay curves.
Cryogenic stimulation is proved to be capable of generating fractures and enhancing the matrix permeability in the near-wellbore area at low injection pressure. The controlling factors in affecting the cryogenic fracturing effect are captured by the modified finite difference model, providing a useful tool for design and predication of field-scale applications.
A successful waterflood can be implemented in a multi-layered tight oil reservoir developed with horizontal multi-fractured wells. This paper forecasts the recovery factor that can be achieved in such a reservoir as well as discusses the challenges of analyzing and modelling tight oil reservoirs developed with multi-fractured horizontal wells.
With some unconventional reservoirs that are hydraulically fractured, a phenomenon exists whereby material balance and simulation indicate pressure support from a water source that is not always obvious. This phenomenon is believed to be related to the multi-layered silts/shales in the reservoir and is not typically seen in simulation of conventional higher permeability reservoirs (Kair >10 mD). Although, the exact petrophysical nature of the silts/shale reservoir layers in this project are not well defined at this time, a successful production history match can be achived by incorporating their input into a simulation model.
In the literature, improvement of oil recovery in smart water injection schemes has been shown to be mediated by wettability alteration. This process reduces residual oil saturation, which in turn affects the microscopic sweep efficiency and leads to subsequent enhancement of overall waterflood performance (
This study presents the effect of lithology on CEC value. Experimental studies on smart waterflooding in tight oil cores have reported reduction of residual oil saturation by as high as five percent and improvement of microscopic sweep efficiency by six percent (
Currently, few studies on smart waterflood in tight and very tight oil reservoirs exist. This work examines smart waterflood opportunities in these reservoirs from both an experimental and a numerical perspective.
Slickwater frac is widely used for stimulating the productivity of unconventional shale and tight reservoirs nowadays. Slickwater produces long skinny fractures, but only the near wellbore region is propped due to fast settling of sand. Adding gel can slow down sand settling, but gel damages the fracture surface and proppant pack. Other issues include large water consumption, water damage, and high water disposal cost. Recently, a non-damaging, less water-intensive fracturing fluid system with improved sand placement efficiency, known as polymer-free foam (PFF), is developed by Gu (2013). The current objective is to study the impacts of sand pumping designs on PFF fracturing efficiency by conducting numerical modeling. In the first step, discrete element method (DEM) and lattice Boltzmann method (LBM) are employed to simulate proppant particle compression, rearrangement, and conductivity for different mesh sizes and areal concentrations under different fracture closure stresses. Next, the conductivity results are input in an in-house fracture propagation model to simulate the fracture conductivity distribution after foam fracturing. After that, the fracture conductivity distribution is input in a reservoir production model to predict the productivity. A parametric study is conducted to understand the impacts of sand mesh size and pumping load on foam frac. With the study, the optimal sand size and concentration are determined for the new fracturing fluid system in shale and tight reservoirs. Our results show, for 140 nD shale gas reservoirs, pumping mesh 100 sand at a volume ratio of 0.15 v/v, 0.125 v/v, and 0.1 v/v are optimal sand pumping designs for PFF treatments with foam quality of 60, 70, and 80%, respectively. If the reservoir permeability is ten times larger, the optimal sand pumping designs for 60, 70, and 80% quality PFF treatments are mesh 30/50 at 0.15 v/v, mesh 100 at 0.125 v/v, and mesh 100 at 0.125 v/v, respectively. With the optimization of sand pumping design, well production can be increased by 110% for low permeability shale, or by 70-100% for high permeability tight or naturally-fractured shale formations. This paper develops a time-efficient workflow to optimize sand pumping strategy for the new PFF fracturing system. The methodology includes coupled DEM/LBM modeling of proppant conductivity, fracture modeling, and reservoir production simulation. The PFF fracturing system with optimized sand mesh size and load can provide enhanced productivity with less water consumption, less gel and water damage, and lower water disposal cost.