Characterizing reservoir fluid composition is a crucial step in all phases of the exploration and development cycle of any oil field. The petroleum industry has dedicated much work to build up computational techniques to model phase behavior through two approaches using conventional regression methods and the Equation-of-State models. Recently, Artificial Neural Networks (ANN) have been successfully used to solve numerous problems in the petroleum industry. This interest is due to the fact that neural networks generally have large degrees of freedom, thus they can capture the nonlinearity of the process being studied better than regression techniques. In addition, neural networks have the ability to model systems with multiple inputs and outputs.
The objective of this study was to develop a neural network model to predict the molar compositions of heavy oil as functions of the well location, depth, bottomhole temperature, bottomhole pressure, API gravity, and gas gravity. Since composition may change vertically as well as laterally, well location and depth of the samples are included in the training of the neural network. A total of nine pseudocomponents are used as output variables.
The data, on which the network was trained, contained 82 data sets collected from Lower Fars heavy oil reservoir of north Kuwait. Several neural network architectures were investigated to obtain the most accurate model. Results indicate that general regression neural network shows optimum prediction capability for molar compositions as functions of the input variables. In addition, the model was able to successfully predict the molar compositions from inputs that were not seen during the training process. The output of this study is in accordance with the new vision and strategy that Kuwait Oil Company has set toward the exploitation of the unconventional heavy oil resources of Lower Fars reservoir of North Kuwait in which a lot of new wells will be drilled in this area. A development of such a new and innovative prediction model using ANN approach is of great importance in providing the molar composition of Lower Fars heavy oil reservoir, starting only from basic available data, with a limitation of a reliable PVT data base.
The development of correlations for the prediction of fluid properties has been the subject of extensive studies. An accurate estimation of these properties is essential for all petroleum engineering calculations. Over the years, several correlations to estimate PVT properties have been reported for different types of hydrocarbon systems. In recent years, the growing demand for energy has increased the attention in heavy oil production. Fluid characterization of heavy oils is required for a number of reasons, consisting of oil quality evaluation, selection and optimization of production processes, facilities planning, transport planning, and process monitoring.
Heavy crude oil has been defined as any liquid petroleum with API gravity less than 20°. It is an unconventional oil resource that is characterized by the high presence of naphthenes and paraffins resulting in viscosities, high densities compared to conventional oil.1 Most of the heavy oil deposits occur in shallow (3000 ft or less), high permeability (one to several Darcies), high porosity (around 30%) poorly consolidated sand formation. The oil saturations tends to be high (50%-80% pore volume), and formation thickness are 50 to several hundred feet.
This paper will cover both caprock integrity and reservoir deformation, drawing from our years of experience in working with the heavy oil/oilsands industry in Alberta, Canada. Theoretical principles are described, analytical derivations made and field examples given, all to help illustrate the fundamentals and summarize the learnings in proactive utilization of geomechanics to enhance the reservoir performance and proactive consideration of geomechanics to ensure the caprock
integrity. Topics include dilation tendency and fracturing behaviour in the oilsands, major geomechanical work components for the caprock integrity analysis/design, mini-frac tests and nonlinear coupled thermo-hydro-mechanical processes.
A completions strategy has been developed for improving both steam injection and production conformance in a thermal- enhanced oil recovery (EOR) project by using intelligent completion technology that incorporates interval control valves (ICVs), well segmentation, and instrumentation. The initial field trial is ongoing in the injector of a Northern Alberta steam-assisted gravity drainage (SAGD) well pair.
Depending on the level of heterogeneity present in the reservoir, the application modeling shows that a 45% reduction in the steam-oil ratio and an almost 70% increase in recovery can be achieved in a SAGD process when both improved injection conformance and producer differential steam-trap control can be applied in a segmented horizontal well pair. A cost-effective intelligent completion solution to achieve this segmentation and control has the potential to add substantial value to field developments resulting in increased energy efficiency and oil recovery through improved steam conformance. The method being developed is also applicable to a wide range of other thermal EOR processes such as cyclic steam stimulation (CSS), steam drive and variations, which include those processes involving solvent additives. The initial field deployment in the injector well was conducted primarily to prove the technology, to demonstrate the feasibility of modifying the steam distribution, and to determine best practices for future developments. A successful installation and commissioning of the intelligent completion has validated the technology substantially. Lessons learned are highlighted.
Early injection test results and data show a significant increase in the understanding of the injection and production behavior in the well pair. The intelligent completion technology under trial and proposed developments should enable more extensive use of downhole measurement and control in thermal EOR projects than has been possible to date.
This paper discusses the development of the completion technology, its applicability to thermal conditions, initial field trial results and the plans for further development. A test program to optimize the distribution of the steam injection in the well is underway, and the results to date also will be discussed.
Viscosity is a key property for evaluation, simulation and development of petroleum reservoirs. The accurate prediction of viscosity will be helpful for, production forecasting, designing future of thermal recovery processes. Reservoir oil viscosity is usually measured isothermally at reservoir temperature. However, at temperature other than reservoir temperature these data are estimated by empirical correlations. Here, based on results of viscosity measurements of 33 heavy crude oil samples of API gravity ranging from 10° and 20° degree, at 68 oF collected from various areas of Kuwaiti oil fields, and tested at 68 to 320 oF. A new correlation has been developed. The validity and accuracy of this correlation has been confirmed by comparing the obtained results of this correlation with other ones along-with the experimental data. The result were satisfactory, in contrast to other correlations which were mostly developed for significantly lighter oils at average reservoir temperatures. Most of them cannot reasonably predict the heavy oil viscosity at elevated temperatures.
Dickson, Jasper Lane (Exxon Mobil Corporation) | Clingman, Scott (ExxonMobil Upstream Research Co.) | Dittaro, Larry Mark (Imperial Oil Ltd.) | Jaafar, Ali E. (Imperial Oil Co.) | Yerian, Jeffrey Alan (Exxon Mobil Corporation) | Perlau, Darrel (Imperial Oil Resources Ltd.)
ExxonMobil and its affiliate Imperial Oil Resources are currently operating a Solvent-Assisted Steam-Assisted Gravity Drainage (SA-SAGD) experimental pilot plant at Cold Lake, Canada. During pilot operation, up to 20 percent by volume of a light hydrocarbon solvent will be injected with dry steam in a dual horizontal well SAGD configuration. The pilot scope consists of two horizontal well pairs (four wells total), six observation wells, associated steam and solvent injection facilities, artificial lift, and dedicated production measurement and testing facilities.
Previous experimental and computer modeling work completed by the Alberta Research Council (ARC) (Nasr, 2003), Imperial Oil Resources, and ExxonMobil indicates that the addition of solvent to the dry steam increases bitumen production rates and decreases the steam oil ratio (SOR) relative to conventional SAGD processes. A key objective of this pilot is to safely collect high-quality field data to support these findings and quantify process improvement.
This paper will focus on the pilot design approach taken to ensure that the multi-year pilot is successful as well as highlight early pilot performance and operation. Specific design aspects which will be discussed include the choice for the pilot location, the use of detailed geologic models to design and place the horizontal wells, and solvent measurements. Early field results are consistent with expectations. However, longer term operation is required to make a more quantitative assessment. In addition, the pilot operation has demonstrated excellent control of injection pressure, which is critical to the application of this technology in settings with bottom water or top gas.
This paper was also prepared for presentation as SPE 149596 at the North Africa Technical Conference and Exhibition, 20-22 February 2012, Cairo, Egypt.
Exploitation of extra heavy oil resource will be the main R & D challenge in the future. In India Mehsana oil field is the one of the extra heavy oil belts. In such type of fields advanced EOR is of primary concern to increase the recovery. Apart from conventional thermal methods this paper discusses about the commercialization and broad application of (MWAGD) as alternative thermal method in the Mehsana oil field. In this study, applicability of microwave heating for heavy oil from
Mehsana heavy oil field was experimented and analyzed quantitatively. In this paper a core sample of Mehsana field is taken and heated with the microwave energy provided by a microwave source consisting of magnetron tubes to generate the microwave power. Micro-Wave radiation is non-ionizing so requires high frequency current (3000 MHz) which causes friction by vibration of molecules which results in dielectric heating of the sample. In this experiment heat transfer between microwave source and core is described quantitatively. Temperature and viscosity profile of the gravity drained oil are observed graphically and analytically. Effects of initial oil and water saturations, wettability, porosity, permeability are discussed with respect to the drained oil. Economic evaluation is also done by comparing the costs in USD/barrel between the above proposed method and the method which is being run presently i.e. Steam Assisted Gravity Drainage (SAGD). In this paper authors have also shown the work-how of applicability of MWAGD in the Mehsana field in present scenario. MWAGD is cost effective than the conventional EOR methods. It is also more efficient and less time consuming as there is speedy heat transfer by dielectric heating. MWAGD does not cause any consequential damage and provides greater oil displacement efficiencies. Also, the heavy deposit of residual coke or carbon is rooted out.
Exploration for heavy oil, in an offshore setting carries special challenges and risks, especially during the well testing phase. Bringing the heavy oil to surface and then disposing of this oil efficiently without polluting the offshore environment is a challenge. Flow testing oil with APIs as low as 8 degrees would be challenging in itself; when this oil is also sour, the challenges are magnified many-fold, especially when considering the limited space on offshore drilling rigs.
Saudi Aramco has started a program aimed at exploration and evaluation of heavy oil reserves in the Arabian Gulf. The objective of testing this sour, heavy oil was to obtain reservoir fluid samples, get productivity data and characterize the reservoir. While attempting to dispose of the oil in an efficient manner, initial attempts to test this heavy oil were unsuccessful. Prematurely terminating these tests resulted in not obtaining all of the required test data.
A heavy oil team was formed in early 2008 to determine solutions to the inability to properly characterize the reservoir on heavy oil well tests. This multidisciplinary team of professionals held two workshops, where heavy oil experts from major service companies provided their global expertise. This information was then blended with local operational requirements to create a unique well testing design. This design has successfully been implemented in two wells (onshore and offshore).
The use of an Electric Submersible Pump (ESP) although common in production scenarios, was successfully implemented for the first time on a heavy oil drill stem test in Saudi Arabia.
This paper summarizes the problems associated with testing heavy oil, the options studied, the reasons for selection of the chosen test method, the downsides of the selected plan, the trial testing on land and the successful implementation of the final plan in an offshore environment. It is a summary of the planning process necessary to get a good heavy oil test in a sensitive offshore environment.
Heavy oil reservoirs constitute a huge proportion of total world oil reserves. Among different thermal recovery methods, steam injection is the most widely used method in this type of reservoirs. Monitoring of swept volume over time is very important for evaluation of a thermal project. Thermal well testing offers an inexpensive method to estimate flow capacity and swept volume in thermal recovery processes. Pressure falloff tests are usually used for this purpose.
Estimation of steam zone properties and swept volume from falloff test data in this study is based on the theory developed by Eggenschwiler et al. (1980), assuming a composite reservoir with two regions of highly contrasting fluid mobilities and the interface as an impermeable boundary. Consequently, the swept zone acts as a closed reservoir for a short duration, during which the pressure response is characterized by pseudo steady state behavior.
The purpose of this work is to investigate the feasibility of thermal well test analysis and effects of different parameters. Pressure falloff testing is simulated using a numerical thermal simulator. The generated pressure falloff data are then analyzed to calculate swept volume and reservoir parameters. Different gridblock models are designed.
Results of this study show that the swept volume, swept zone permeability and skin factor can be reasonably estimated from pressure falloff tests. The effects of gravity, dip, permeability anisotropy and irregular shapes of swept zones are investigated. It is found that these factors do not affect the estimated results significantly. Results of 3D models show that the estimation of flow capacity and steam swept volume depends on the vertical positions where pressure data are measured (i.e. the location of pressure gauges). This finding should be considered in thermal well test interpretation.
Kuwait has a considerable reserve of untapped heavy oil; plans were developed by KOC and embarked on a project to increase its oil production by 2020. Heavy oil production is an ambitious project and will be significant contributer to the overall increase in oil procuction capacity.
As the term "heavy oil?? suggests, it is a very viscous oil. The most common methods of heavy oil recovery are:
- Cold Heavy Oil Production with Sand (CHOPS)
- Cyclic Steam Stimulation
- Steam Flooding
- Steam Assisted Gravity Drainage (SAGD)
With the focus on the second method, Cyclic Steam Stimulation to enhance the recovery of heavy oil, the design of the cement became important in terms of endurance over the life of the well. In this technique the casing / cement would be exposed to steam injection temperatures as high as 500°F.
In such cases, the cement sheath may crack due the extreme forces acting on the thin sheath of the cement. It is therefore important to know the Young's modulus of both the formation and the cement. This will allow the slurry properties to be adjusted by the use of additives to lower the Young's modulus of the cement to less than of that of the formation. This will prevent damage to the cement sheath.
A fit-for-purpose cement slurry was designed accordingly and applied on a South Ratqa well. Well testing during and after 45 days of steam injection demonstrated that the cement maintained its integrity despite the challenging conditions.
Cement Slurry Design
A project was initiated to investigate the mechanical integrity of various cement slurries subjected to 500°F steam-injection cycles. The overall aim was to achieve a flexible cement design that would withstand the induced stress applied in this particular situation. (Figure 1).
Live samples (cement, location water and additives) were air-freighted to the USA (Baker Hughes Pressure Pumping Technology Center in Texas) to avoid any design flaw factors, and maintain reproducible slurries upon actual job execution.
The cement slurry testing was done as per the schedule shown in Figure 1. This schedule was applied to most testing, including the determination of the following parameters:
- Destructive compressive strength
- Ultrasonic compressive strength
- Unconfined tensile strength
- Confined tensile strength
- Ultrasonic Young's modulus
- Ultrasonic Poisson's ratio
- Confined Young's modulus
- Confined Poisson's ratio
A noticeable increase in a carbonate reservoir permeability (relative to that of core) and calibration of the reservoir mobile water saturation resulted from its black model history match to 56-year primary production history.
The First Eocene carbonate reservoir of Wafra field contains a large amount of heavy oil (13-19 oAPI). Primary recovery since 1956 has been approximately 4 percent of the net OOIP. Steamflood has been piloted in the field since 2005. Full field steamflood performance forecasting relies heavily on reservoir simulation, which requires proper calibration of models. Long history of the field primary production is a valuable source of information for such a calibration.
Based on core data, the reservoir is not considered fractured and was modeled as a single porosity system. The model initial average horizontal permeability was about 200 md with a maximum of about 1000 md. The 258-million-cell full field geostatistical model was upscaled to a 3.6-million-cell simulation model with the reservoir heterogeneity preserved. Oil viscosity depth variation was incorporated.
The model was matched satisfactorily. Well productivity indices were increased to enable each of more than 300 wells to produce at reported liquid rates. Permeability was globally increased. An aquifer was included to match reservoir pressure. Resulting average horizontal permeability did not exceed 2-3 Darcy. Recent MDT tests support this permeability level.
Irreducible water saturation (Swir) was modified to match water production. First approximation of Swir was based on core data. Then Swir was multiplied by a factor. The resulting amount of mobile water seems modest within the producing interval and rapidly growing towards the OWC. This mobile water may become a steam thief zone.
The calibrated distributions of model permeability and mobile water will be used in steamflood forecasting.