Steam injection is a widely used oil-recovery method that has been commercially successful in many types of heavy-oil reservoirs, including the oil sands of Alberta, Canada. Steam is very effective in delivering heat that is the key to heavy-oil mobilization. In the distant past in California, and also recently in Alberta, solvents were/are being used as additives to steam for additional viscosity reduction. The current applications are in field projects involving steam-assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS).
The past and present projects using solvents alone or in combination with steam are reviewed and evaluated, including enhanced solvent SAGD (ES-SAGD) and liquid addition to steam for enhancing recovery (LASER). The use of solvent in other processes, such as effective solvent extraction incorporating electromagnetic heating (ESEIEH) and after cold-heavy-oil production with sand (CHOPS), are also reviewed. The theories behind the use of solvents with steam are outlined. These postulate additional heavy-oil/bitumen mobilization; oil mobilization ahead of the steam front; and oil mobilization by solvent dispersion caused by frontal instability. The plausibility of the different approaches and solvent availability and economics are also discussed.
The development of unconventional shale-gas formations in North America with horizontal multifractured wells is mature enough to identify production malpractices and abnormal productivity declines generally observed within 18–24 months of initial production. The primary objective of this study is to address all known causes of these productivity declines and to develop a fully coupled geomechanical/flow simulation model to simulate these production conditions.
This model mimics the effect of depletion-induced in-situ stress variations on short-term and long-term productivity by taking into account several phenomena, such as stress-dependent matrix and natural-fracture permeability as well as reduction in hydraulic-fracture conductivity caused by proppant crushing, deformation, embedment, and fracture-face creep. Matrix-permeability evolutions, considering the conflicting effects of non-Darcy flow and compaction, have also been accounted for in this model. Numerical solutions for simplified hydraulic-fracture planar geometries are then obtained by use of a finite-element-method scheme.
A synthetic case was defined to investigate the effects of each individual phenomenon on short-term and long-term production. Results show that the combined effects of permeability alterations in matrix and natural fractures as well as conductivity losses in hydraulic fractures may result in substantial cumulative-gas-production loss. The model also reproduces familiar field-observed trends, with lower long-term production corresponding to higher drawdowns. This behavior is attributed to the stress-dependent evolution of reservoir permeability and hydraulic-fracture conductivity. The results show that ignoring the effects of any of the previous phenomena results in overestimation of ultimate recovery. Furthermore, it is shown that proper management of pressure drawdown and the penalty for lower initial production rates in unconventional shale-gas reservoirs can yield substantially higher ultimate recovery.
The model is fully versatile and allows modeling and characterization of all widely differing (on a petrophysical level) shale-gas formations as well as proppant materials used for the stimulation treatments. This integrated model can be used for optimization of key parameters during the hydraulic-fracture design, for fine tuning production history matching, and especially as a predictive tool for pressure-drawdown management.
Saini, Dayanand (California State University, Bakersfield) | Wright, Jacob (California State University, Bakersfield) | Mantas, Megan (California State University, Bakersfield) | Gomes, Charles (California State University, Bakersfield)
A critical analysis of the key geological characteristics, completion techniques, and production behaviors of the Monterey Shale wells and their comparisons with analogous major US shale plays—namely, the Bakken and the Eagle Ford—may provide insights that could eventually help the petroleum industry unlock its full potential. The present study reports on such efforts.
The Monterey Shale is very young and geologically heterogeneous compared with the Eagle Ford and the Bakken. Oil viscosity in the Monterey Shale is significantly higher, and one can also notice that Monterey oil production has declined over the years. The Monterey Shale has a field-dependent completion strategy (pattern spacing and fracturing stage), while a horizontal, uncemented wellbore completion is common in the Bakken and the Eagle Ford. In the Monterey, nonhydraulically fractured zones of horizontal and hydraulically fractured wells appear to be making approximately equal contributions to the well’s cumulative production. The ongoing water-disposal operations in overlying injection zones, up to a certain extent, have affected the productivity of both types (long and short production histories) of wells. The geology also appears to have an effect on the production behaviors of horizontal and hydraulically fractured wells.
A preliminary economic analysis suggests that exploitation of the Monterey Shale is still a profitable venture. However, for sustainable development in a current price regime of USD 50/bbl of crude oil, it is necessary that production costs be reduced further. Also, compared with the Bakken and the Eagle Ford, the Monterey sits in regions of extremely high water stress (i.e., frequent occurrences of drought or drought-like conditions). However, oilfield-produced water associated with current steamflooding-based oil- and gas-production operations in the region as a base fluid suggests that it can potentially meet most of the water demand for future fracturing jobs. Also, combined use of a centralized water-management system; a less-costly, more energy-efficient, and high-capacity solar-powered desalination system; and a final sludge-management and/or residual-brine-disposal mechanism might assist the petroleum industry in managing flowback and produced waters while keeping water-handling costs low.
A combination of new enhanced-oil-recovery (EOR) methods for releasing the remaining oil from both nonfractured and fractured zones of horizontal wells and the use of oilfield-produced and recycled water for completing hydraulically fractured horizontal wells might prove to be a significant change for the future exploitation of California’s Monterey Shale resource, which is subject to the toughest hydraulic-fracturing regulations in the nation and is in a region of extremely high water stress.
Guo, Hu (China University of Petroleum, Beijing) | Li, Yiqiang (China University of Petroleum, Beijing) | Kong, Debin (China University of Petroleum, Beijing) | Ma, Ruicheng (China University of Petroleum, Beijing) | Li, Binhui (China University of Petroleum, Beijing) | Wang, Fuyong (China University of Petroleum, Beijing)
Although the alkali/surfactant/polymer (ASP) flooding technique used for enhanced oil recovery (EOR) was put forward many years ago, it was not until 2014 that it was first put into practice in industrial applications with hundreds of injectors and producers in the Daqing Oil Field in China. In this study, 30 ASP-flooding field tests in China were reviewed to promote the better use of this promising technology. Up to the present, ASP flooding in the Daqing Oil Field deserves the most attention.
Alkali type does affect the ASP-flooding effect. Strong alkali [using sodium hydroxide (NaOH)] ASP flooding (SASP) was given more emphasis than weak alkali [using sodium carbonate (Na2CO3)] ASP flooding (WASP) for a long time in the Daqing Oil Field because of the lower interfacial tension (IFT) of the surfactant and the higher recovery associated with NaOH than with Na2CO3. Other ASP-flooding field tests completed in China all used Na2CO3. With progress in surfactant production, a recent large-scale WASP field test in the Daqing Oil Field produced an incremental oil recovery nearly 30% higher than most previous SASP recoveries and close to the value of the most-successful SASP test. However, the most-successful SASP test was partly attributed to the weak alkali factor. Recent studies have shown that the WASP incremental oil recovery factor could be as good as that of SASP but with much-better economic benefits.
Screening of surfactant by IFT test is very important in the ASP-flooding practice in China. Whether dynamic or equilibrium IFT should be selected as criteria in surfactant screening is still in dispute. Many believe the equilibrium IFT is more important than the dynamic IFT in terms of the displacement efficiency; thus, it is better to choose a lower dynamic IFT when the equilibrium IFT meets the 10–3 order-of-magnitude requirement. However, it is impossible for many surfactants to form ultralow equilibrium IFT. Because of the low acid value of the Daqing crude oil, the asphaltene and resin components play a very important role in reducing the oil/water IFT and asphaltene is believed to be more influential, although more work is required to resolve this controversial issue.
Whether polymer viscoelasticity can reduce the residual oil saturation is still a matter of debate. Advances in surfactant production and in the overcoming of scaling and produced-fluid-handling challenges form the foundation of the industrial application of ASP flooding. Further work is advised on the emulsification effect of ASP flooding. According to one field test, the EOR routine should be selected depending on consideration of the residual oil type to decide whether to increase the sweep volume and/or displacement efficiency. The micellar flooding failure in one ASP field test in China has led all subsequent field tests in China to choose the “low concentration, large slug” technical route instead of the “high concentration, small slug” one. ASP flooding can increase oil recovery by 30% at a cost of less than USD 30/bbl; thus, this technique can be used in response to low-oil-price challenges.
Zhu, Daoyi (China University of Petroleum, Beijing) | Hou, Jirui (China University of Petroleum, Beijing) | Wei, Qi (China University of Petroleum, Beijing) | Chen, Yuguang (China University of Petroleum, Beijing)
The PG Reservoir in Jidong Oil Field is at a depth of approximately 4500 m with an extremely high temperature of approximately 150°C. The average water cut has reached nearly 80%, but the oil recovery is less than 10% after only 2 years of waterflooding process. It is of great importance to develop a high-temperature-resistant plugging system to improve the reservoir conformance and control water production. An in-situ polymer-gel system formed by the terpolymer and a new crosslinker system was developed, and its properties were systematically studied under the condition of extremely high temperature (150°C). Suitable gelation time and favorable gel strength were obtained by adjusting the concentration of the terpolymer (0.4 to 1.0%) and the crosslinker system (0.4 to 0.7%). An increase of polymer and crosslinker concentration would decrease the gelation time and increase the gel strength. The gelant could form continuous 3D network structures and thus have an excellent long-term thermal stability. The syneresis of this gel system was minor, even after being heated for 5 months at the temperature of 150°C. The gel system could maintain most of the initial viscosity and viscoelasticity, even after experiencing the mechanical shear or the porous-media shear. Core-flow experiments showed that the gel system could have great potential to improve the conformance in Jidong Oil Field.
Several tools and techniques exist to understand distributions of reservoir properties. Interwell tracer testing is one of the most common methods to obtain reservoir information from the amount of tracer produced. The capacitance/resistance model (CRM) is an analytical tool to estimate connectivity between producer/injector pairs from historical rates and, when available, bottomhole-pressure data in waterfloods. Because the CRM is a physically based, simple input/output model, its combination with tracer testing can provide insight into reservoir features.
To enable the CRM application to tracer flow, we incorporated tracer models, based on miscible-displacement theory, into the CRM. Reservoir properties are estimated as a result of the model fitting to produced-tracer data. In this paper, we present three tracer models: a dispersion-only (short-range autocorrelation) model, a Koval (long-range) model, and a combination of the two. To incorporate the tracer models into the CRM, we used two methods, serial fitting (CRM then tracers) and simultaneous fitting (CRM and tracers).
We applied these techniques to tracer data from 10 injectors and 10 producers of the Lawrence Field. Results suggest that interwell connectivity obtained from the CRM is in good agreement with the observed peak-tracer concentrations. All tracer models are capable of giving a good fit in most of the cases. After comparing the tracer models, we determined that the combined model can represent a tracer flow better than the other two models alone. We also found that the simultaneous-fitting method gives the best fit to total producer-rate data and tracer data. Simultaneous fitting mitigates the nonuniqueness of the fits, leading to an improvement of tracer matching. The reservoir properties obtained in this study (Koval factor and dispersion coefficient) also were analyzed and compared with those from previous measurements.
Liu, Hui-Hai (Aramco Services Company) | Lai, Bitao (Aramco Services Company) | Zhang, Jilin (Aramco Services Company) | Huang, Xinwo (Aramco Services Company) | Chen, Huangye (Aramco Services Company)
This work proposes an innovative laboratory method to measure shale gas permeability as a function of pore pressure, a key parameter for characterizing and modeling gas flow in a shale gas reservoir. The development is based on a solution to 1D gas flow under certain boundary and initial conditions. The details of the theoretical background, including formulations to estimate gas permeability and conceptual design of the test setup, are provided. The advantages of our approach, surpassing the currently available ones, include that it measures gas permeability (as a function of pressure) with a single test run and without any presumption regarding the form of parametric relationship between gas permeability and pore pressure. In addition, our approach allows for estimating both shale permeability and porosity at the same time from the related measurements. Numerical experiments are conducted to verify the feasibility of the proposed methodology.
Kamal, Medhat M. (Chevron) | Morsy, Samiha (Chevron) | Suleen, F. (Chevron) | Pan, Yan (Chevron) | Dastan, Aysegul (Chevron) | Stuart, Matthew R. (Chevron) | Mire, Erin (Chevron) | Zakariya, Z. (Chevron)
A new method is presented that uses transient well testing to determine the in-situ absolute permeability of the formation when three phases of fluids are flowing simultaneously in the reservoir. The method was verified through simulation using synthetic data, and its applicability and practicality were confirmed through application to field data. Determining the absolute permeability over the reservoir scale using readily available transient testing data will have major benefits in accelerating history matching and improving reservoirperformance prediction.
A recently developed method (Kamal and Pan 2010) to determine the in-situ absolute permeability under conditions of two-phase flow extended the applicability of transient well testing and has been adopted in commercial software. In this study,
The method presented in this study uses surface flow rates and the fluid properties of the three phases. It also uses the same relative permeability relations used in the simulation models, thus ensuring that the same permeability values calculated from field data are used in history matching and predicting the performance of the reservoir. It is assumed that the fluid saturations are relatively uniform in the region around the well at the time of the transient test. The method was verified by comparing the input values with the results obtained from analyzing several synthetic tests that were produced by numerical simulation. Data from a deepwater field were also used to test the practicality and validity of the method. For the field case, the method was verified by matching reservoir production and pressure using the calculated absolute permeability. Excellent agreements were obtained for both synthetic and field cases.
Norouzi, Hamidreza (Institute of Petroleum Engineering, School of Chemical Engineering) | Rostami, Behzad (Institute of Petroleum Engineering) | Khosravi, Maryam (IOR Research Institute) | Shokri Afra, Mohammad Javad (Institute of Petroleum Engineering, School of Chemical Engineering)
In the current survey, the time required to rupture the water film shielding the oil as a result of oil swelling caused by the diffusion of dissolved gas in the water phase and trapped oil behind it has been investigated in porous medium at high pressure and temperature. To study the active mechanisms, the experiments have been conducted with two different types of injectants: carbon dioxide (CO2) and methane (with different solubility in water), under different miscibility conditions at equal reduced pressures. Experimental observations have been interpreted using theoretical studies. Furthermore, the time of water-film rupture has been identified in production data and matched by an analytical model. This time and its monitoring during various gas-injectant types and regimes under reservoir conditions have not been previously addressed.
The results show that water film reduces the performance of oil recovery by limiting the interface of oil and gas phases. Under such a condition, the best scenario is miscible gas injection because the gas can effectively swell the oil and rupture the water shield. At miscible and near-miscible conditions, the time required to eliminate the water film increases as the injectant solubility in water decreases; however, there is a negligible difference at the immiscible regime. The trend of oil-recovery curves after rupture of the water film shows that oil swelling is one of the main mechanisms involved in water-trapped oil recovery. These results suggest practical guidelines to better understand the effect of the water-shielding phenomenon in the field of tertiary gas injection. The outcome of this integrated study could effectively increase the knowledge of shielded oil recovery using different gas-injectant types under various miscibility conditions and could prepare the required basis for compositional simulation of waterflooded oil production during tertiary gas injection.
Estimation of total reserves in shale/gas and shale/oil reservoirs is challenging but critical. Different logging tools and core-evaluation procedures are used to address this challenge. Nuclear magnetic resonance (NMR) plays a vital role in understanding fluid content, rock/fluid interaction, and determination of pore-body-size distributions. Hydrocarbon (HC)-hosting pore systems in shale includes both organic and inorganic pores. Recoverable HCs include bitumen and light HCs. Their relative fractions are strongly dependent on thermal maturity. Regardless of detailed chemical characterization, “bitumen” is simply defined on the basis of mobility in this study. The apparent mobility of HCs depends on fluid composition, solubility, and reservoir temperature. Historically, NMR laboratory-calibration measurements (nominally, 2-MHz) on core are conducted at room temperature (25–35°C). This study highlights the importance of running NMR tests at reservoir temperature. Experiments were performed for both bulk fluids and fluid-saturated rock samples.
The results show that, at a specific temperature, NMR responds only to the fraction of HCs present in the liquid phase. For routine NMR measurement, at 31°C, only the relaxation signals of compounds more volatile than C17 are acquired. Thus, the C17+ fraction would be invisible to NMR at room temperature, but perhaps not at reservoir temperature. This is critical to the interpretation of NMR log response within the early oil and condensate windows, in which C17+ can be a major fraction. Thus, engineers can underestimate movable HCs by using routine core data as a basis for interpretation.
On the basis of NMR experiments for several oil samples, we observed that the T1–T2 distributions depend on the overall composition of total HCs and effective mobilities. The results also show that, in the case when both light and heavy HC fractions coexist in a single phase, they do not appear as different clusters in a T1–T2 distribution map. NMR parameters were used to monitor the amount, composition, and effective mobility of remaining HCs after each injection and discharging cycle, during miscible enhanced-oil-recovery (EOR) huff ’n’ puff experiments on Eagle Ford samples.