In this paper, techniques have been developed to experimentally evaluate performance of CO2 injection in heavy oil reservoirs for pressure maintenance purpose. More specifically, a three-dimensional (3D) physical model consisting of five vertical wells and three horizontal wells is used to examine effect of well configurations on pressure maintenance and oil recovery with CO2 injection in heavy oil reservoirs. The initial oil saturation, oil production rate, water cut, gas-oil ratio, ultimate oil recovery, and distribution of residual oil saturation are examined under various well configurations, which can be optimized to maximize heavy oil recovery when CO2 injection is employed for pressure maintenance purpose. The well configuration with a horizontal producer plus four vertical injectors is found to achieve a better performance than the conventional five-spot well configuration, while the oil recovery is experimentally determined to be 15.7% of OOIP during CO2 injection process.
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.
ExxonMobil and its Canadian affiliate Imperial Oil Resources are pursuing an integrated research program targeted at developing the next generation of heavy oil recovery processes which utilize hydrocarbon solvents as a mobilizing agent. The key benefits of solvent-based processes are improved environmental performance, improved economics and recovery of resource that is impractical with thermal processes.
The integrated research program encompasses fundamental laboratory work, analytical modeling, advanced numerical modeling, scaled physical modeling in the laboratory, a solvent-only pilot which is in the design phase, an operating solventassisted SAGD pilot and a first commercial scale application of a solvent-assisted cyclic steam stimulation (CSS) process known as Liquid Addition for Steam Enhanced Recovery (LASER). This paper provides a systematic review of the scope, technical challenges, benefits and successes of research efforts in each of the areas cited above. In general, the results of laboratory modeling and simulation studies are strongly supportive of the potential success of solvent-assisted and solventbased recovery processes. Reliably demonstrating solvent recovery processes at the field scale remains a key challenge that can only be addressed through well designed field pilot programs and enhanced reservoir surveillance programs for commercial scale applications. These challenges are highlighted in the paper utilizing specific examples from the integrated research program.
In conclusion, there are some very significant technical challenges that need to be addressed before solvent-assisted and solvent-based heavy oil recovery processes will be broadly commercialized. Nonetheless, consideration of the results across the full breadth of ExxonMobil's integrated technology program provides strong support that a new generation of solvent recovery processes will emerge as an economically competitive option for heavy oil recovery with significant environmental benefits relative to today's thermal recovery processes.
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
In this paper, techniques have been developed to examine the enhanced swelling effect and viscosity reduction of CO2-saturated heavy oil with addition of rich solvent C3H8. Experimentally, PVT tests are conducted to measure the saturation pressure, swelling factor and viscosity of the C3H8-heavy oil system and C3H8-CO2-heavy oil system, respectively. It has been found that an increased swelling effect of heavy oil is obtained by adding rich solvent C3H8 into CO2 stream. An enhanced viscosity reduction of the CO2-heavy oil system is also achieved in the presence of rich solvents such as C3H8. Theoretically, two binary interaction parameter (BIP) correlations in Peng-Robinson equation of state (PR-EOS) have been proposed for respectively characterizing CO2-heavy oil systems and C3H8-heavy oil systems by treating each oil sample as a single pseudocomponent with its molecular weight and specific gravity. The BIP correlations together with the PR-EOS can be used to predict the saturation pressures and swelling factors of the C3H8-CO2-heavy oil systems with a good accuracy. Also, in comparison to other mixing rules, the Lobe's mixing rule is found to be more appropriate for quantifying viscosity reduction of the heavy oil with dissolution of CO2 and/or C3H8.
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.
Tillero, Edwin (Petroleos de Venezuela S.A.) | Perez, Ender (PDVSA) | Gonzalez, Javier (PDVSA) | Ferreira, Diomar (Ameriven) | Ungredda, Alessandro (Halliburton) | Griborio, Guillermo Ernesto (Halliburton) | Mogollon, Jose Luis (Landmark)
The studied reservoir has one of the greatest heavy-oil reserves (OOIP about 12.2 MMMSTB) in the Maracaibo Lake basin. It has been largely developed except for one coastline area (385 km2), which includes both zones' land and shallow water. Limited access of conventional drilling rigs in the area, coupled with low definition of the structural, stratigraphic, and petrophysical model have reduced drilling activities.
Plans have been made to increase production by 20% through drilling of wells in the coastline area. This plan requires the consideration of multiple variables, such as new surface facilities, drilling rigs for both geographical environments, rock heterogeneity, compartmentalized structure (6 blocks), low number of drilled wells (8 wells), and limited reservoir data, which will generate a large number of development scenarios.
This paper presents a probabilistic production forecasting of the coastline reserves through an innovative approach based on a systematic evaluation of risk and uncertainty of reservoir variables, and a maximization of net present value (NPV). The optimization of a large number of decision variables, such as the type of drilling rigs, type of wells completion, and seismic acquisition zone, was obtained. The optimal stochastic scenario showed a NPV with a 340% increase compared with the best deterministic scenario.
This approach triggered warnings about the current plans for seismic data acquisition, which proved to be uneconomical despite expected improvements in the geological and stratigraphic framework. Therefore, the drilling of stratigraphic wells becomes an alternative to partially substitute seismic survey. Finally, the different operational scenarios showed that development should be done in stages and by geographical areas, starting with stratigraphic deviated wells into shallow water zone using conventional rigs, then vertical and slanted wells in shallow water zone using swamp rigs, and verticals and slanted wells in the ground region using land rigs.
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.
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.
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.