Lei, Zhengdong (Research Institute of Petroleum Exploration and Development, Petrchina) | Li, Junchao (Research Institute of Petroleum Exploration and Development, Petrchina) | Tang, Huiying (College of Engineering, Peking university)
During waterflooding process, the characteristics of injection water induced fracture propagation and resulting percolated fracture network remain unclear and are of great importance for the optimization of waterflood performance. In this paper, a coupled geomechanics and flow model based on discrete fracture model is developed to model the fracture propagation induced by injected water. A displacement discontinuity method is applied to simulate the stress redistribution and newly formed fractures. The fracture geometry is updated and re-gridding procedures are carried out according to the situation at the certain time step. A validate case and a real field case are studied and results demonstrate the effectivity of the proposed method.
F field is located in the Middle East and was discovered in 1980's. The bulk of the proven liquid hydrocarbons are contained in the B formation (carbonate), which averages some 200m in thickness in the study area. The hydrocarbons are contained in a low relief NW-SE trending anticlinal structure. Deposition of the reservoir sequence occurred during the late Cemnomanian to Early Turonian in the Mesopotamian Basin.
Oil production started few years ago and currently there are more than 40 producing wells in the centre of the structure. The uneven well distribution limits the understanding of 3D reservoir characterisation, explicitly in the flank areas. Only one conventional core with good recovery was available for reservoir B, which makes it somewhat difficult to delineate the internal architecture of the carbonate ramp.
A total of seven lithofacies were identified which are Rudistic Floatstone Wackestone, Bioclastic Wackestone, Bioturbated Bioclastic Packstone (BBP), Rudistic Rudstone Wackestone, Bioclastic Floatstone Wackestone, Heterolithic Bioturbated Bioclastic Wackestone and Bioclastic Mudstone. A conceptual depositional environment with lithofacies association was generated by using core descriptions, regional studies and analogues.
A fit for purpose integrated reservoir characterisation study was carried out in 2014 with main inputs from Nuclear Magnetic Resonance (NMR) and image logs in conjunction with digital rock analysis (DRA), conventional open hole well logs, core laboratory analysis, mud logs, pressure and well test data. Several rock typing approaches were developed; including Flow Zone Indicator (FZI) or Rock Quality Index (RQI), Lucia Rock Class, Clerke Pore Size technique from Mercury Injection Capillary Pressure (MICP), multi-variate cluster analysis (biased and normalized), cluster analysis (non-biased and non-normalized) and self-organizing maps (biased but non-normalized). From these FZI, an optimum of seven Hydraulic Units (HU) were selected where FZI 1 being the best flow unit, and FZI 7 is the poorest.
A relationship between FZI with lithofacies was then established by comparing both on depth plot as well as porosity-permeability cross plot. Different FZI can be seen for one lithofacies, for instance BBP consists of FZI 1 to 4 which indicates the changes in reservoir quality within the same lithofacies. The same relationship was extended towards depofacies, and resulted with lateral segregation of depositional environment according to its reservoir quality.
This exercise confirms the heterogeneity within B formation, and it captures the changes in reservoir quality laterally and vertically. This detailed understanding of the carbonate architecture was translated into a 3D geological model in order to minimize the uncertainties for dynamic simulation and future field development plans.
A cloud-distributed optimization algorithm applicable to large scale, constrained, multi objective, optimization problems, such as steamflood redistribution, is presented. The proposed algorithm utilizes the so-called Metamodel Assisted Evolutionary Algorithm (MAEA) as its algorithmic basis. MAEAs use a generic implementation of an evolutionary algorithm as their main optimization engine and advanced machine learning techniques as metamodels. Metamodels are utilized through the application of an inexact pre-evaluation phase during the optimization, which substantially decreases the evaluations of the problem specific forward model. Additionally, a unification of global search (GS) and local search (LS) is achieved via the use of Lamarckian learning principles applied on top of a MAEA creating, in essence, a Metamodel Assisted Memetic Algorithm (MAMA). MAMAs profit from the abilities of MAEAs to explore the most promising regions of the design space without being trapped in local optima while also utilizing the efficiency of deterministic methods to further refine promising solutions located during GS. At the end of each EA generation, the most promising members of the current populations are selected to undergo LS using a gradient-based method. Further, integration with scalable cloud-distributed computing allows MAMAs (CD-MAMA) to perform rapid and simultaneous evaluation of tens of thousands of operating plans.
The proposed algorithm has been statistically validated on two mathematical test cases and, subsequently, used to optimize a field undergoing steamflood under two different oil-price scenarios.
Thus, demonstrating that, cloud-distributed MAMAs coupled with efficient reservoir models, allow for steamflood injection redistribution optimization in affordable, by industry, wallclock times (hours). For the field in question production comes from poorly consolidated sands within the Antelope Shale member of the Miocene Monterey formation with porosity averaging 30%, permeability averaging 2,000 mD and net thicknesses typically between 50 and 300 feet. Structural dip is steep at approximately 60 degrees. The reservoirs are shallow, with depths ranging from 200 – 600 feet TVD. Oil gravity is approximately 13° API. Reservoir pressures are well below bubble point and average 50 – 100 PSI. The field has about 200 producers and 30 injectors, producing about 2000 bpd of oil and injecting 8000bpd of steam. The field has been under operation for about 7 years, with most of the continuous steamflood starting about 3.5 years ago.
The main goal of the reservoir modeling including heavy oil ones by means of any deterministic model is to predict their further development results. A similar problem is solved by decline curves. We propose a new system that combines both approaches. The developed model was called adaptive. The main advantage of the adaptive approach is the possibility to modify the mathematical apparatus of the model, depending on the uncertainty of geological and production data.
The volume of initial information to construct the adaptive model is comparable to the volume of initial information to construct any deterministic model. The structure of the adaptive model also suggests the presence of deterministic geological and hydrodynamic components. However, they are based on different principles than the deterministic models. The mathematical apparatus of adaptive modeling is based on the use of such approaches as a non-parametric statistics, fuzzy logic, numerical solution of differential equations, and intelligent algorithms.
On the basis of the developed approach, the adaptive geological and hydrodynamic models of the Permian - Carboniferous reservoir of the Usinsk field, which is the largest one according to its value of remaining recoverable reserves of heavy oil in the Timan-Pechora region of Russia were created. The main objective of reservoir simulation using the adaptive model is to determine which cells of the model obtained the produced oil and water, and where they remained less, and where the injected water or steam went. For the adaptive hydrodynamic models, the absolute values of reservoir parameters are not important; their diversity between neighboring cells is more significant.
A new approach to the construction of geological and hydrodynamic models of heavy oil reservoirs based on the principle of fully discrete simulation which can be used to solve the most of the known problems associated with the reservoir development and increase of oil recovery on such complex objects including the forecast of efficiency of work-over techniques measures (drilling of new wells, cycle steam stimulation, water shut-off works, etc.).
Takabayashi, Katsumo (INPEX) | Shibayama, Akira (ZADCO) | Yamada, Tatsuya (INPEX) | Kai, Hiroki (INPEX) | Al Hamami, Mohamed Tariq (ZADCO) | Al Jasmi, Sami (ZADCO) | Alrougha, Hamad Bu (ZADCO) | Yonebayashi, Hideharu (INPEX)
The objective of this paper is to overcome the asphaltene risk evaluation usually conducted snapshot basis. We evaluate the temporal change in the asphaltene risks as gas injection proceeds. In reservoirs under gas injection, in-situ fluid component gradually changes by multiple contacting with the injection gas. Those compositional changes affect asphaltene stability and bring difficulty into the risk predictions by asphaltene models. This study aims to reduce the risk uncertainty depending on operational condition changes.
Periodical upgrading of asphaltene model is essential for understanding the time-depending changes of asphaltene risks. In the previous study (
According to the previous study recommendation, additional asphaltene laboratory studies were conducted on the basis of newly collected samples. All Asphaltene On-set Pressure (AOP) detected from the new samples were higher than those of the previous study. Especially, a large difference was observed from the past/present results of the lower reservoir's AOPs even though samples collected from the identical well. Asphaltene precipitation risk was observed to increase largely because the new AOP was detected at the reservoir temperature while no AOPs detected in the previous study. The difference might be occurred by saturation pressure increase. Then, the numerical asphaltene models were revised, and accordingly, the asphaltene risk estimation were updated higher in the lower reservoir. For the upper reservoir, the past/present AOPs were slightly changed to become higher. The reference sample fluids were collected from two different wells showing minor difference of asphaltene contents. Those variations might be caused by geological heterogeneity that could affect on fluid maturity. Then, the risk rating was updated to be slight higher, too. In this paper, through the comparison between the previous and current studies, it was pointed out the importance of regular monitoring asphaltene risks.
This study provides the valuable findings of time-lapse evaluation of asphaltene precipitation risks for reservoir under gas injection. The evaluations currently conducted in the industry are snapshots of instantaneous risks. Through entire field life, the risks have varied depending on operating conditions. This study argued the risk-change in the unique field by the identical workflow but using each representative data collected at different times. Finally, this study demonstrated the importance of time-depending fluid dynamics.
Xiao, Cong (China University of Petroleum, Beijing) | Tian, Leng (China University of Petroleum, Beijing) | Wang, Yanchen (Downhole Service Company of Shengli OilField Service Corporation, Shandong, China) | Yang, Yaokun (China University of Petroleum, Beijing) | Gao, Yan (Exploration and Development Institute of Huabei Oilfield Company Development Planning Office, Hebei, China) | Chen, Sheng (Xibu Drilling Engineering Company, CNPC, Xinjiang, China)
Accurate identification of fracture scale and connectivity is of significance for reservoir engineers to efficiently model fluid flow in naturally fractured reservoir. This paper utilized semi-analytical pressure- transient model to qualitatively detect fracture scale and connectivity for naturally fractured reservoir. First, we proposed conceptual models to characterize fractured reservoir:dual-porosity continuum (coupled matrix and small-scale fracture) and discrete fracture system (large-scale fracture). Second, line source function of two-dimensional dual-porosity continuum and one-dimensional flow model within discrete fracture system were established, respectively. Through numerical discretion, superposition theory, Gauss elimination and Stehfest numerical algorithm, pressure-transient solution and type curves were obtained. On the basis of proposed model, model validation was implemented, and methodology to qualitatively detect fracture scale and connectivity in naturally fractured reservoir using pressure- transient characteristics was also described. Our results shown that no matter what the flow state (steady-state or unsteady state flow) within fracture system, we could qualitatively detect connectivity of large-scale fracture based on whether a "dip" shape occurs at the stage of formation radial flow regime, while the connectivity of small-scale fracture lies in whether the value of dimensionless pressure derivative curve is equal to 0.5 at formation radial flow regime. For the large-scale fracture with connecting well, the more the flow regimes within large-scale fracture and the more lately the bi-linear flow regime occurs, the larger the fracture scale. For the large-scale fracture without connecting well, the more significant the "dip" shape and the earlier the "dip" shape occurs, the larger the fracture scale. Radial composite model can strongly interfere our proposed methodology to detect the scale and connectivity of large-scale discrete fracture system. Through interference analysis, difference between our model and composite model lies in the facts that the pressure-derivative values from the point at which the last valley occurred increase more quickly in a discrete-fracture system than those in a composite model. Our valuable results can provide theoretical guidance for fracture detection and characterization in naturally fractured reservoir.
Wang, Ziji (E&D Research Institute of Liaohe Oil Field Company, CNPC) | Han, Bing (E&D Research Institute of Liaohe Oil Field Company, CNPC) | Zou, Zhaoyu (E&D Research Institute of Liaohe Oil Field Company, CNPC)
Liaohe field is one of the largest heavy-oil fields in China. Its D-N Block is a deep massive ultra-heavy oil reservoir undertaking SAGD development, which will serve as a case study in this paper. Part of the dual horizontal wells had used cycle steam stimulation to start up the SAGD process but it generated severely uneven distributions of temperature, pressure, and saturation around wells due to the high reservoir heterogeneity. An improved steam circulation start-up methods instead of cycle steam stimulation is needed to overcome the problems.
We developed an optimization method by coupling the wellbore-reservoir simulation for steam circulation using a specialized thermal wellbore simulator and a commercial thermal reservoir simulation, and carefully considering the structure of the wellbore, fluid flow in the wellbore and reservoir characteristics. We found out several dominating factors on the heat loss and efficiency of steam circulation by considering the properties of tubing, annulus, liner, fluid components and formations on a conceptual model. Using an advanced criterion by monitoring the temperature distributions near the wellbore, wellbore operations including the injection rate and circulation period, the tubing strings layouts and other critical operation parameters are designed according to the features of downhole conditions to ensure a more homogeneous development of the steam chamber.
The simulation workflow and optimum circulation start-up stratergy was applied to a pilot dual-horizontal well group in the D-N Block. Steam circulating start-up process both in the wellbore and the reservoir was successfully simulated and compared with the conceptual model case. After optimization, reservoir simulation results showed a much better behavior in the start-up and the subsequent SAGD stage, mitigating the risk of steam fingering, resulting in a steady transition to SAGD stage. Monitoring data from downhole temperature sensors also suggested a favorable process. For example, temperature data in a series of time showed that the temperature between the horizontal wells kept increasing uniformly, which indicated that the steam chamber connects the two wells in a favorable manner. Comparing with the cyclic steam stimulation start-up and the steam circulation without optimization, the optimized steam circulation achieved much better recovery efficiency in SAGD process.
In this paper, a systematic workflow has been described which couples the simulation of the reservoir characteristics and wellbore conditions. Optimized operation guideline was implemented into the SAGD wells and overcame the uneven start-up of dual-horizontal wells. This achievement can be applied to other SAGD wells in Liaohe, and probably extended to other fields.
Hinai, Nasser. M. Al (Department of Petroleum Engineering, Curtin University, Commonwealth Scientific and Industrial Research Organization, Australia, Petroleum Development Oman L.L.C.) | Saeedi, A. (Department of Petroleum Engineering, Curtin University, Commonwealth Scientific and Industrial Research Organization, Australia, Petroleum Development Oman L.L.C.) | Wood, Colin D. (Department of Petroleum Engineering, Curtin University, Commonwealth Scientific and Industrial Research Organization, Australia, Petroleum Development Oman L.L.C.) | Valdez, R. (Department of Petroleum Engineering, Curtin University, Commonwealth Scientific and Industrial Research Organization, Australia, Petroleum Development Oman L.L.C.)
Field A, located within the Harweel cluster in southern Oman, has been recognised as a viable miscible gas injection candidate. However, the mobility ratio of such a flood is unfavourable due to the low viscosity of the injected gas (0.01 to 0.04 cP) as compared to that of the in-situ oil (0.24 cP). One approach to overcome this issue is to thicken the injected gas to effectively control the gas mobility and increase the sweep efficiency.
This study will present the details of a numerical reservoir simulation study, which assesses the potential benefits of adding polymers to the injected gas to increase the viscosity. Considering the composition of the AG in Field A, we have examined a number of different AG compositions to include different levels of hydrocarbon gas and CO2. We have also evaluated the direct effect of the different gas compositions on the oil properties during the flood.
The simulation was carried out using CMG-GEM and the associated PVT module CMG-WinProp. A full-field 3D geological model has been built based on the typical geological characteristics and the light oil fluid properties in Field A. The simulation model takes into account the reservoir heterogeneities and future design considerations of the enhanced oil recovery (EOR) project to be implemented in the field.
The results confirm that increasing the injected gas viscosity close to that of the oil has a significant effect on the gas mobility, time of breakthrough and the ultimate recovery in Field A. It has also been observed that the oil viscosity reduction with natural gas dissolution is much more pronounced than that achieved with the pure CO2. Such an effect resulted in 4% higher oil recovery by the injection of thickened natural gas (76%) than the thickened pure CO2 (72%). Furthermore, bacause gas breakthrough is delayed, a low gas-oil ratio can be maintained during the injection. These results demonstrate the real advantages of thickening the natural gas over CO2 for improving the gas flood efficiency in a light oil reservoir such as Field A.
The contribution of this study is significant considering the fact that to date there have been limited studies evaluating the effect of thickened natural gas for EOR. Most of the previously completed research work in this area have mainly focused on the identification of thickener polymers for CO2 injection processes.
The effectiveness of a hydraulic fracturing technology has been primarily attributed to a creation of the geometry in the primary fracture. This concept however has been challenged particularly in low-permeability formations in which the size of a Stimulating Reservoir Volume (SRV) becomes the most important issue. Unlike the primary fracture, the area in the SRV is controlled by the fundamental geomechanics behaviors of the formation and a secondary fracture network propagation with possible different modes, and more importantly by the formation permeability change which is controlled by the induced stresses near the primary fracture. In this paper, the induced stresses near a hydraulic fracture in a pure elastic, poroelastic, dual-porosity media are analyzed and compared in order to characterize the low-permeability, sandstone and fractured formations, respectively. The general formulation for a fractured reservoir by a dual porosity model is developed and pore pressures and stresses near a wellbore and a hydraulic fracture are highlighted for production enhancement as the permeability change near a wellbore or a hydraulic fracture may contribute to such an enhancement significantly. Those key parameters controlling the pressure and stresses change and numerical method used are analyzed and presented.
Production and processing operations of crude oil require a thorough understanding of phase behavior. To model asphaltenes, we need to know more about their phase behavior. The model has to incorporate the interaction of asphaltene and oil in terms of solubility in oil and the suspension characteristics attributed to resin.
This paper reports a comprehensive phase behavior study for five wells from the Middle East was performed as part of an asphaltene precipitation study. The study outlined several important concepts and detailed procedures for modeling asphaltene phase behavior using WinProp, which uses the Nghiem model for asphaltene precipitation