Salehi, Amir (Quantum Reservoir Impact International LLC) | Hetz, Gill (Quantum Reservoir Impact International LLC) | Olalotiti, Feyisayo (Quantum Reservoir Impact International LLC) | Sorek, Nadav (Quantum Reservoir Impact International LLC) | Darabi, Hamed (Quantum Reservoir Impact International LLC) | Castineira, David (Quantum Reservoir Impact International LLC)
An integral aspect of smart reservoir management of oil and gas fields is the process of identifying and performance forecasting of the remaining, feasible, and actionable field development opportunities (FDOs). In the present work, we introduce an adaptive full-physics simulation-based forecasting framework that applies a series of cutting-edge technologies to provide short- and long-term forecasts for both field- and well-level performance. Our workflow can be applied to a comprehensive opportunities inventory including behind-pipe recompletion, infill drilling, and sidetrack opportunities. In our approach, we begin with a model order reduction technique, which involves a parsimonious elimination of redundancies existing in a given geologic model. This involves an adaptive model upscaling strategy that retains fine details in the vicinity of critical geological features by locally varying the resulting model grid resolution. Reduced models, which are validated using streamline-based flow metrics, are passed into an automated sensitivity study and model calibration engine for efficient reconciliation of observed production trends in the field. Here, we apply a recently proposed Ensemble Smoother robust Levenberg- Marquardt (ES-rLM) method to generate plausible model realizations that replicate the reservoir energy. Representative models are further improved in a sensitivity-based local inversion step to match multiphase production data at the well level. An approach alternative to streamlines, which is compliant with a general unstructured grid format, is utilized to directly compute production data sensitivities on the underlying grid in the local inversion module. Finally, calibrated models are directly passed to the optimization and forecasting engine to assess and optimize field opportunities and development scenarios. This framework has been successfully applied to several giant mature assets in the Middle East, North America, and South America. A case study for one of the giant reservoirs in Latin America is presented where hundreds of field development opportunities are initially identified. We then apply our forecasting framework to the various scenarios including all opportunities to deliver the optimum field development plan. We propose a systematic workflow for field-scale modeling and optimization using an adaptive framework. Our approach facilitates a flexible framework to rapidly generate reliable forecasts and quantify associated uncertainties in a robust manner. This advantage in flexibility and robustness is tied to our fast and automated two-stage model calibration module that leads to substantial savings in computational time. This makes it an efficient method for quantifying the uncertainty as demonstrated through improved estimation of the faults’ connectivity, permeability distribution, fluid saturation evolution, and swept volume.
Olalotiti-Lawal, Feyi (Texas A&M University) | Onishi, Tsubasa (Texas A&M University ) | Kim, Hyunmin (Texas A&M University ) | Datta-Gupta, Akhil (Texas A&M University ) | Fujita, Yusuke (JX Nippon Oil & Gas Exploration Corporation) | Hagiwara, Kenji (JX Nippon Oil & Gas Exploration Corporation)
We present a simulation study of a mature reservoir for carbon dioxide (CO2) enhanced-oil-recovery (EOR) development. This project is currently recognized as the world’s largest project using post-combustion CO2 from power-generation flue gases. With a fluvial formation geology and sharp hydraulic-conductivity contrasts, this is a challenging and novel application of CO2 EOR. The objective of this study is to obtain a reliable predictive reservoir model by integrating multidecadal production data at different temporal resolutions into the available geologic model. This will be useful for understanding flow units along with heterogeneity features and their effect on subsurface flow mechanisms, to guide the optimization of the injection scheme and maximize CO2 sweep and oil recovery from the reservoir.
Our strategy consists of a hierarchical approach for geologic-model calibration incorporating available pressure and multiphase production data. The model calibration is performed using regional multipliers, and the regions are defined using a novel adjacency-based transform accounting for the underlying geologic heterogeneity. The genetic algorithm (GA) is first used to match 70-year pressure and cumulative production by adjusting pore volume (PV) and aquifer strength. Water-injection data for reservoir pressurization before CO2 injection is then integrated into the model to calibrate the formation permeability. The fine-scale permeability distribution consisting of more than 7 million cells is reparameterized using a set of linear-basis functions defined by a spectral decomposition of the grid-connectivity matrix (Laplacian grid). The parameterization represents the permeability distribution using a few basis-function coefficients that are then updated during history matching. This leads to an efficient and robust work flow for field-scale history matching.
The history-matched model provided important information about reservoir volumes, flow zones, and aquifer support that led to additional insight compared with previous geological and simulation studies. The history-matched field-scale model is used to define and initialize a detailed fine-scale model for a CO2 pilot area that will be used to study the effect of fine-scale heterogeneity on CO2 sweep and oil recovery. The uniqueness of this work is the application of a novel geologic-model parameterization and history-matching work flow for modeling of a mature oil field with decades of production history, and which is currently being developed with CO2 EOR.
The Lower Cretaceous McMurray Formation in western Canada has over 1.8 trillion barrels of bitumen resource in place. Due to the bitumen in its natural state having a very low API (6-12°) and corresponding high viscosity, traditional primary (pump jacks) and secondary (water flood) recovery techniques cannot be used. Instead, economic extraction of the bitumen occurs via surface mining and subsurface steam-assisted gravity drainage (SAGD). Using the Pike and Jackfish oil sands project areas as a case study, it will be shown that successful SAGD operations requires a thorough understanding of the depositional fabric and stratigraphic architecture of the reservoir.
Within the study area, reservoir intervals in the form of cross-bedded sandstones and sandy inclined heterolithic strata (IHS) are present within both the middle and upper McMurray. Overlying the middle McMurray are upper McMurray parasequence cycles reflective of brackish bays and deltaic embayment deposits. In many areas, however, these parasequences are absent and instead substituted by fluvial channels with brackish water overprint. The facies within these fluvial channels are very similar in character to the those seen within the middle McMurray. To help progress our understanding of baffles and barriers to flow within these aforementioned reservoir facies, dip meter and seismic data are presented as data that can be used. From this, a better understanding of the complex interplay of facies and stratigraphic relationships can be made. More importantly, clearer insights into SAGD performance (pre- and post-steam) can also be achieved.
Using the McMurray Formation as an underpinning, the wider implications of understanding fluvial sedimentation will be addressed by using reservoirs from the Middle East as examples. For example, many siliciclastic reservoirs in locations such as Kuwait (Wara Formation) and Iraq (Zubair Formation) are also influenced to a large degree by fluvial sedimentation. Not unlike SAGD, any successful secondary recovery techniques applied within these reservoirs will also require a detailed characterization of the channel stacking patterns and channel orientations prior to implementation.
Energy sources are vital to sustain and grow the world economy. As of today, the world mainly relies on fossil fuel as the source of energy for transportation, power generation, chemicals manufacturing, and other industrial applications. The conventional sources of hydrocarbon are steadily declining; however, the oil and gas industry has been successful in finding unconventional hydrocarbons, such as heavy oil and shale gas. There are distinct challenges in producing and processing the hydrocarbons from unconventional sources into usable end products. Reducing the footprint during the production of oil, refined products, and gas will benefit the industry by reducing the overall cost and improving the health, safety, and environmental impact.
International major Shell announced Thursday that it has agreed to sell off the majority of its stake in Canadian oil sands projects in a cash and stock deal valued at USD 8.5 billion. Canadian Natural Resources will acquire from Shell its entire 60% interest in the Athabasca Oil Sands Project (AOSP), 100% of the interest in the bitumen-processing Peace-River Complex, and other undeveloped properties in Alberta, Canada. In a second deal, Shell and Canadian Natural are to jointly purchase Marathon Oil's Canadian subsidiary, which holds a 20% interest in the AOSP for USD 3 billion in cash. Shell said the deal represents a net value of USD 7.25 billion, the cash portion of which will be used to pay down its debt load. Shell estimates that the assets being sold to Canadian Natural hold 2 billion bbl of reserves.
The integration of seismic data into high-resolution geological model, provides great potential for calibrating reservoir parameters, which enables better understanding of the reservoir sweep and flow patterns. The efficacy of seismic inversion method based on the travel time of fluid saturation front using seismic onset times has been well demonstrated for integrating frequent time-lapse seismic surveys. However, due to the high cost associated with conducting seismic surveys, frequent seismic surveys are usually not commonly available. In this paper, I have generalized the onset time inversion method for infrequent seismic data using interpolated seismic onset times, making the method applicable for efficiently integrating infrequent seismic surveys. With the valuable information provided by seismic data, the uncertainty in the reservoir model parameters can be reduced through history matching. The history matched model can be used to optimize reservoir management and field development strategy. The proposed method is illustrated using synthetic and field applications.
The streamline based technology has proven to be effective for various subsurface flow and transport modeling problems including reservoir simulation, model calibration and optimization. For naturally fractured systems, current streamline models are well suited for dual porosity single permeability systems because streamlines need to be traced only for the fracture system. However, complications arise for dual porosity dual permeability (DPDP) systems because streamlines need to be traced for both fracture and matrix systems. Also, the streamlines in the two systems may interact. We present a robust streamline tracing framework for use in the DPDP models via an embedded discrete fracture model (EDFM) framework.
The EDFM models utilize irregular gridding and non-neighbor connections to explicitly represent the discrete facture network. Our strategy is based on a boundary layer method that can be used to honor the fluxes at the matrix-fracture interface during streamline tracing. We generalize our previously proposed streamline tracing algorithms for local grid refinements (LGR) and faulted systems to discrete fracture network models where a fracture gridblock in EDFM is treated as a boundary layer for flux continuity and streamline tracing. The proposed method is benchmarked with a semi-analytical solution and a series of numerical examples encompassing different levels of geologic and geometrical complexity to illustrate the accuracy and robustness of the approach. Visualization of streamlines in complex fracture networks provide flow diagnostics such as sweep efficiency and connectivity of wells and fractures. The streamlines are then utilized to develop a workflow for rate allocation optimization for waterflood in naturally fractured reservoirs. We utilized a streamline-based gradient free algorithm whereby both injection and production rates are adjusted under realistic operational constraints. This approach only requires a few forward simulations and therefore offers significant advantages in terms of computational efficiency. It is confirmed that the optimized schedule provides improvements in oil recovery and sweep efficiency compared to the base scenario with uniform injection and production rates.
The uniqueness of this work is the robust streamline tracing algorithm in the EDFM using a novel boundary layer based approach for flux continuity. The proposed approach is simple and easy to implement and can be coupled with commercial simulators for field scale applications.
Liang, Guangyue (Research Institute of Petroleum Exploration and Development, CNPC) | Liu, Shangqi (Research Institute of Petroleum Exploration and Development, CNPC) | Liu, Yang (Research Institute of Petroleum Exploration and Development, CNPC) | Luo, Yanyan (Research Institute of Petroleum Exploration and Development, CNPC) | Han, Bin (Research Institute of Petroleum Exploration and Development, CNPC) | Huang, Jixin (Research Institute of Petroleum Exploration and Development, CNPC) | Bao, Yu (Research Institute of Petroleum Exploration and Development, CNPC)
Steam assisted gravity drainage (SAGD) process is widely used in super heavy oil and oil sands projects. These projects generally have higher steam to oil ratio and poor economy, partly because un-uniform steam chamber along the horizontal section forms and it is hard to adjust, affecting by reservoir heterogeneity including muddy interlayer and thief zones. Therefore, it is desirable to explore realistic and promising technology measures for SAGD projects at low oil price.
In this paper, almost all the technology measures for SAGD projects were extensively and deeply investigated in terms of domestic and foreign reports, literatures and on-site experiences. The available research subjects include Xinjiang Fengcheng and Liaohe super heavy oil projects in China as well as ten oil sands project attached to eight corporations in Canada. Better yet, numerous statistics about technology application are reviewed well-by-well, and field application effects for some technologies were verified by deliberate numerical simulation.
Many realistic and enforceable technology measures were systematically analyzed and recommended. Single or multiple stage dilation start-up process assisted by waste water or polymer injection enhanced start-up process significantly. Infilling well pairs or wedge well, and sidetracking horizontal well or fishbone well effectively tapped the unswept remaining oil by steam. The other technologies further improved steam chamber conformance including non-condensable gas co-injection, ICD/FCD technology, differentiated operating pressure strategy, nitrogen plus dispersant foam profile control and other remedial measures, etc. Besides, the present situation and foreground application were summarized and evaluated for several promising new technologies to be studied such as screening low cost mixed solvent to increase solvent recovery, warm solvent gravity drainage (Nsolv) process and in-situ upgrading process assisted by electrical heater or catalytic modification to reduce the capital cost of surface facility, etc.
The paper contains some previously unpublished data of practical experiences, and the findings of this investigation add to the knowledge base information related to improving the SAGD performance and economy of super heavy oil or oil sands projects.
Heavy oil is a promising substitute to conventional light oil due to its abundant reserves, but its high viscosity restricts mobility and results in low recovery rate. To enhance heavy oil recovery, thermal method with metal-ligand compounds was developed, which reduced oil viscosity permanently and upgraded oil
For thermal in-situ oil sands production, it is conventional to think that an emulsion pipeline remains essentially oil-wet. Ideally, an oil coating distributed on the pipe by the produced water-in-oil emulsion from a well pad is expected to give the needed corrosion protection for the operating life of the pipeline. Practically however, there are conditions under which this ideal scenario becomes no longer feasible, even for low API gravity heavy oil. These parameters affecting protection include but are not limited to water cut, well pad processing, steam cycle phenomena, reservoir characteristics, pipeline operating temperature, partitioning characteristics of the acid gases and their effects on water chemistry and passivation as well as other field operational practices.
From the experience of two case histories at a thermal in-situ oil sands project, this paper elaborates on many of the field parameters and how they influence the integrity of pipeline infrastructure by studying the various corrosion phenomena at play. Corrosion mitigation recommendations for these pipelines will also be presented.
Consideration of corrosion mechanisms in thermal oil recovery facilities should be divided into two categories, conditions with and without microorganisms present; the former is called microbiologically influenced corrosion (MIC). Constant monitoring of these facilities for MIC and controlling them when present is essential to corrosion management. If corrosive microorganisms are present in significant amounts, the probability of failure is high despite the presence of other corrosion mitigating factors including assumptions about oil-wetting, passive scale formation or the efficacy of a chemical inhibition program. This paper deals with non-microbiological corrosion issues and considers the following factors in the context of thermal oil production: