Recovery of Nigerian Heavy Oil: Application of Steam Flooding

Aims: Nigeria has a lot of conventional and heavy oil resources. Although much of the conventional oil resources have been developed since independence, the heavy oil resources have remained underdeveloped due to low recovery based on primary production and consequently doubts about economic viability based on the current fiscal regime. This paper examines the application of Steam Flooding enhanced oil recovery (EOR) method to suitable Nigerian heavy oil reservoirs, seeks to develop a diagnostic model to predict the performance, evaluates the economics to determine the viability of the EOR method. The development of heavy oil will increase Nigeria’s oil reserves and production. Study Design: Data was collected for two heavy oil reservoirs from two oil companies in Nigeria following a Non-disclosure Agreement (NDA). Place and Duration of Study: Emerald Energy Institute, University of Port Harcourt Nigeria, 2016 - 2021. Methodology: The screening criteria of commercially effective EOR methods were applied to select steam flooding for the studied reservoirs. Design of Experiment (DoE) was used to evaluate the reservoirs and operating parameters and to determine their optimum values, which were then used to predict the performance of the reservoirs. The economics of the steam flood technique endorsed for the reservoirs considered were also evaluated using Discounted Cash Flow Analysis (DCFA). Results: These assessments confirmed that steam flooding technique was technically and economically viable for the heavy oil reservoirs considered. The steam flood was observed to have a good recovery efficiency of 24%, as against the waterflooding technique which had 13% OOIP and natural depletion of 9% for the offshore reservoir. For the onshore reservoir, the recovery efficiency was 20% for steam flood, and 4% for natural depletion. The economic analysis showed that even at a worst-case heavy oil price of US$15, the project was viable. Conclusion: Steam flooding is viable, can be applied to develop heavy oil reservoirs in Nigeria that meet the screening criteria, and thus increase national oil reserve and production. Recommendation: The fiscal policy should be adjusted, especially the petroleum profit tax from 85% to 50% as an incentive to operators and investors to embark on steam flooding and other EOR methods.

Encouraging Preliminary Results of Steam Flood Pilot Project in Unconsolidated Reservoir with Strong Water Drive, Sultanate of Oman

Observed performance of the specially designed steam flood pilot project (implemented and currently operating in the unconsolidated, strong water drive and relatively deep of Mesozoic Sand reservoir in IXYZM Field, Sultanate of Oman) indicates encouraging results of thermal EOR. This reservoir has been produced under primary cold production with horizontal wells but production history and simulation models indicate that ultimate recovery, even with dense well spacing, will be limited to less than 15% of OOIP. Cyclic steam stimulation has been applied in several wells prior to steam flood pilot implementation to confirm steam injectivity and productivity improvement. Reservoir simulation and analytical analysis led to the design of a two-pattern pilot using 2 vertical injectors and 3 horizontal producers. Steam injection started in late 2018 and a complete surveillance program is undergoing to monitor all key parameters related to injection and production performance.

Comparing Steam Flood Analytical and Simulation Models ~ Strengths and Limitations

Mathematical Models are needed to aid in defining, analyzing, and quantifying solutions to design and manage steam floods. This paper discusses two main modeling methods – analytical and numerical simulation. Decisions as to which method to use and when to use them, requires an understanding of assumptions used, strengths, and limitations of each method. This paper presents advantages and disadvantages through comparison of analytical vs simulation when reservoir characterization becomes progressively more complex (dip, layering, heterogeneity between injector/producer, and reservoir thickness).While there are many analytical models, three analytical models are used for this paper:Marx & Langenheim, Modified Neuman, and Jeff Jones.The simulator used was CMG Stars on single pattern on both 5 Spot and 9 Spot patterns and Case 6 of 9 patterns, 5-Spot. Results were obtained using 6 different cases of varying reservoir properties based on Marx & Langenheim, Modified Neuman, and Jeff Jones models.Simulation was also done on each of the 6 cases, using Modified Neuman steam rates and then on Jeff Jones Steam rates using 9-Spot and 5-Spot patterns.This was done on predictive basis on inputs provided, without adjusting or history matching on analog or historical performance.Optimization runs using Particle Swarm Optimization was applied on one case in minimizing SOR and maximize NPV. Conclusion from comparing cases is that simulation is needed for complex geology, heterogeneity, and changes in layering. Also, simulation can be used for maximizing economics using AI based optimization tool. While understanding limitations, the analytical models are good for quick looks such as screening, scoping design, some surveillance, and for conceptual understanding of basic steam flood on uniform geologic properties. This paper is innovative in comparison of analytical models and simulation modeling.Results that quantify differences of oil rate, SOR, and injection rates (Neuman and Jeff Jones) impact on recovery factors is presented.

Numerical Evaluation of the Impact of Steam Quality on Steam Flood Performance in a Kuwait Heavy Oil Reservoir

The objective of this study is to assess any opportunities to improve field recovery or thermal efficiency by evaluating different steam quality scenarios and their impact on the performance of the cyclic steam stimulation and steam flood in Lower Fars reservoir. In this study, simulation history matching of the dynamic test data from the ongoing thermal pilots was used to validate the static and dynamic description. The process results in an improved dynamic model to be used specifically for the steam quality scenarios evaluation, which was then used in the prediction mode for deciding on an optimum steam quality percentage for the upcoming steam flood operation. Different bottom-hole steam quality scenarios are defined using different steam quality output values at the steam generator and a fixed amount of surface network heat loss. The wellbore heat losses are explicitly modelled to arrive at bottom hole steam quality corresponding to a boiler steam quality. The impact of the steam quality on the cumulative amount of oil produced is significant when an economic steam oil ratio cutoff is applied. There was an overall 40% difference in cumulative oil production between low and high steam quality cases, and a 30% difference when an energy cut off criterion was applied instead of the steam oil ratio cutoff. The highest steam quality resulted in the best performance in terms of oil recovery and energy efficiency. Analysis of the results show that the effect of steam quality is different during different periods of the CSS/SF process and mainly related to the different amount of enthalpy injected. During the CSS period a lower steam quality results in lower oil recovery but at a better efficiency compared to a high steam quality. In the steam flood phase the high steam quality results in both higher recovery and higher energy efficiency. The latter is caused by lower over and underburden heat loss. The bottom hole steam quality is a measure of the energy content of the steam that is delivered to the reservoir. This has a significant impact on the efficiency of the thermal recovery process. The steam quality can vary as function of well location and time for numerous reasons. Thus, it is essential to understand how these variables affect the recovery process.

Well Integrity Issues in Steam Flood Injection Wells, Karim Small Field Cluster

Two (2) steam flood vertical injection wells are under operation for the last 15 months in a two- pattern pilot. Previous steam injection experience in this reservoir did not indicate serious issues due to the short injection periods for cyclic steam stimulation (CSS) but several well integrity issues have been faced during the steam flood period. Key issues include high wellhead growth, steam leak to the annulus A, annulus between 7” production casing and 4-1/2” injection tubing, and groundwater vapor behind 9.625” surface casing. Negative impacts from these issues on the continuity and effectiveness of the steam flood are recognized and need to be resolved comprehensively. All wells in the steam flood pilot were drilled and completed based on designs and procedures according to thermal well compliance including well equipment, and cementing specification. Production casing was equipped with thermal expansion collars to support reduction in wellhead growth. Completion strategy uses seal bore packer with bore extensions to accommodate tubing movement and Vacuum-Insulated-Tubing to provide maximum thermal insulation. However, the presence of a total- loss zone near the surface (starting from 50 m depth) affects the cement isolation between surface casing and 12.25” open hole. Daily monitoring is performed on each well where key injection parameters and well responses are recorded. Maximum wellhead growth reached 61 cm within the first week and steam leak from the injection string to annulus A started after 6 months of steam injection. Soon after that, groundwater vapor starts to arise from the gap between 9.625” casing and 12.25” open hole. These series of failures occurred in both injection wells within 3 months apart from each other. It is believed that the steam leak to annulus A resulted in thermal transmission to groundwater vapor. Hoist entries to both injectors indicated that Injector-1 has tubing seal assembly stuck inside seal bore and resulted in parted tubing collar while Injector-2 has tubing seal assembly damage. Both wells have thick oil covering the retrieved seal bore packer. Remedial actions were performed, including a complete change-out of the seal bore packer assembly and top-job cement fill up to surface using fast-set cement to isolate the gap between 9.625” casing and 12.25” open hole to reduce wellhead growth. As a result, the maximum wellhead growth became only 19 cm and 4 cm in Injector-1 and Injector-2, respectively. These remedial actions also led to restoring well and thermal integrity. Retrieved seal bore packer was sent back to manufacturer for appropriate failure analysis and providing useful feedback reports on the above issues. Monitoring and observation data along with failure analysis should provide vital information and possible improvement in completion strategy for steam injection wells that are planned for continuous steam flood projects in similar reservoirs.

On the optimum operating temperature for steam floods

The technical, environmental and economic performances of a steam flood are partly influenced by the operating temperature (pressure). However, the definition and procedure for determining the optimum operating temperature are still debatable. Employing a combination of analytic modelling and numerical simulations, this paper investigates the existence (or otherwise) of an optimum injection temperature Topt for saturated-steam floods. Considering the maximization of productivity and thermal efficiency as objective, an analytic procedure, which explores the effects of temperature on injectivity, total steam enthalpy, oil viscosity and relative permeabilities, shows that the operating temperature (pressure) of a steam flood should not exceed 515 K (3.5 MPa). A simple closed-form expression is proposed for Topt as a function of basic rock and fluid properties. For an example three-dimensional reservoir model comprising an 8-m oil shale unit sandwiched between two sandy units each 15 m thick, numerical simulations show sensitivity to temperature (and viscosity effect) in the range 350–450 K, but becomes increasingly insensitive in the band 500–650 K. It is established that ~500–550 K is the optimum band when the optimization objective is to maximize both discounted oil recovery and cumulative oil-steam ratio. These results agree with an optimum injection temperature of ~501 K estimated from the proposed analytical model in this case. Therefore, based on the results of the analytical model, thermal simulations and other considerations, it is concluded that the optimum steam-injection temperature is project and system specific. The insights gained should find relevance in the design and management of steam floods, as well as other steam-based recovery processes.

The Pilot, Elke, Blakeney, Narwhal, Harbour and Feugh fields, Blocks 21/27, 21/28, 28/2 and 28/3, UK North Sea

The, as yet undeveloped, heavy-oil fields of the Western Platform contain about 500 MMbbl of oil in place. The fields are reservoired in highly porous and permeable, Middle Eocene, deep-water sandstones of the Tay Sandstone Member, deposited as turbidite flows from a shelf immediately to the west.Oil gravity varies from 19° API in the Harbour Field to 12° API in the northern end of the Pilot Field. The reservoirs are shallow: Pilot and Harbour are at about 2700 ft TVDSS, with the Narwhal, Elke, Blakeney and Feugh discoveries being deeper at about 3300 ft TVDSS. Overall, oil viscosity decreases and API oil gravity increases with depth.To date, the high oil viscosity has precluded development of these discoveries, and many previous operators have considered various development schemes, all based on water flood.The development of the Pilot Field is being planned using either a hot-water-flood, steam-flood or polymer-flood approach, which all have the potential of achieving a very high recovery factor of 35–55%. Steam has been evaluated in most detail and about 240 MMbbl could be recovered should all of these discoveries be steam flooded.