|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Often when evaluating waterfloods, the focus is on issues at the well level: pumping fluid off a producer or making sure an injector doesn’t have plugged perforations. These are important issues that need to be addressed to optimize a waterflood, but focusing solely on the wells makes it easy to forget that each well is only one part of a bigger system. Losing sight of the reservoir means losing sight of other influencing factors that are affecting each well’s individual performance. Everything is connected and each change made on a single well affects all wells across the field. For this reason it is important to diagnose a waterflood from multiple viewpoints: the field, pattern, and well levels. At the field level, the goal is to understand the reservoir as a whole. Knowing its history leads to knowing its current state and predicting how it will behave in the future. Every question is a piece to the puzzle and the more questions answered the closer you are to seeing the big picture.
Thermal EOR projects are technically and economically challenging projects. Improving the geological understanding and implementing these geological concepts into the static model were key to increase the robustness of, not only the geological model but also of the dynamic simulation.
The initial believe was that fine grained and mm scale laminated sediments act as vertical baffles for the steam distribution. The fine grained sands were low in permeability and the lamination were further reducing the vertical permeability. Grain size had the main impact on permeability and grain size was correlated with V-shale. Then, V-shale was used as a proxy for grain size and was integrated into a V-shale base porosity-permeability transformation.
After modeling the baffles explicitly, it was shown that against the initial belief, the main control on fluid flow was not a patchy baffle distribution. Instead the reservoir was overall reduced in vertical permeability. A lager impact had the V-shale base poro-perm transform, predicting an order of magnitude permeability range for a given porosity. Reducing the impact of the facies also reduced overall the uncertainty and improved the predictive power of the models. This in turn, helped to take development decisions with much higher confidence.
Heavy oil extraction requires heat introduction to the reservoir to enhance the mobility of oil. While steam injection is one of the most reliable thermal EOR methods for heat introduction, it has several operational, technical, economic, and environmental limitations. This study investigates the effectiveness of a newly developed downhole steam generator which not only minimizes the heat losses due to distance the between generation and injection but accomplishes oil production with lower steam and energy requirements. A test of the downhole steam generator took place in a small 20 acre area northeast Texas with 13 wells accessing a shallow (540 feet TVD) heavy oil bearing sandstone. The viscosity and API gravity of the heavy oil was reported as 3,000 cP at 100 °F and 19 °API. The initial oil and water saturation were approximately 65% and 35% respectively.
Steam injection was started in April of 2013 at steam rates of up to 1300 bbl/day of 600°F steam, producing a total of 540 million BTU per day. The steam front was carefully monitored with temperature readings through oil sampling, both on an individual well basis. According to the temperature readings, steam front movement was faster than typical steam flooding cases in such high viscosity oil reservoirs. Preferential steam propagation occurred towards the northwest of the field due to reservoir dipping towards the southeast. The oil production increased on both the 20 acre test site and wells outside of the test site. The varying distances between injection wells and production wells enabled us to observe steam propagation at varying length. Thus, we could acquire produced oil sampling at varying steam exposure times at different locations and depths. Viscosity, density, and compositional analyses were carried out on the produced oil samples. It has been observed that the viscosity and density of produced oil were not improved due to emulsion formation which is a common concern for any steam injection project. However, further analysis revealed that emulsion breaking is possible with the use of asphaltene insoluble solvents or cationic surfactants. Since the novel design of the downhole steam generator allows injection of any additional chemical with steam during the process, these chemicals could be added to the steam stream to enhance the effective steamed area and reduce the flow assurance related problem. The new downhole steam generation tool provides an opportunity to generate steam in-situ and co-inject steam with additional chemicals to prevent emulsion formation and asphaltene precipitation. Thus, this study proves that downhole steam generation can be feasible for heavy oil extraction, even for small, low-rate fields, if all drawbacks (such as emulsion formation and asphaltene precipitation) are considered and the chemicals injected with steam are selected properly.
Schwartz, Kenneth M. (Chevron North America Exploration and Production Company) | Meier, Holly (Chevron North America Exploration and Production Company) | Star, Allison (Chevron North America Exploration and Production Company) | Stolte, Natasha (Chevron North America Exploration and Production Company)
The First Bone Spring sand received much of the drilling focus as horizontal development began in the Delaware Basin. As development moved south, deeper into the basin, operators began targeting the upper First Bone Spring sand and the emerging lower First Bone Spring shale. This stacked sequence of mixed lithologies of tight sands and organic-rich shales can be characterized as a hybrid play. Ultimately the best wells are landed in the sand, however, shale wells also showed enhanced production volumes deeper in the basin and commonly stacked with a thick sand. The Bone Spring can rival the rig-dominant Wolfcamp formation.
The Delaware Basin is the western sub-basin of the Permian Basin and is currently under active horizontal development of the Wolfcamp and Bone Spring Formations. The Delaware Bain is structurally defined by the Ouachita thrust belt to the south, Central Basin Platform to the east and the Basin and Range-influenced Diablo Platform to the west. The Leonardian-age Bone Spring Formation has three distinct sandstone sequences, known as the First, Second, and Third Bone Spring, isolated by thick carbonate packages. This paper will focus on the youngest sand sequence, the First Bone Spring. The First Bone Spring was the focus of early horizontal development in 2009 through 2012 in the Northern Delaware Basin, but has mostly been under-developed.
Operators were targeting the higher porosity zones within the low resistivity “tight” sand intervals. The low-resistivity log response across the sands reflects the clay content within the sands but also the presence of interbedded organic-rich to semi-pelagic shales, thus termed a hybrid play.
The Bone Spring Formation is roughly 3000 feet thick, comprised of slope to basin siliciclastic and carbonate rocks formed through repeated reciprocal sedimentation. As sea level rose, highstand carbonates were deposited along the basin rim. Sea level stabilized and carbonate debris flows entered the basin followed by maximum sand accumulation during lowstands. Aeolian sand build-ups were wind swept into the basin with a focused deposition along the northern rim. Subaqueous turbidities carried these sands deep into the basin axis where they terminated as submarine fans.
Al-Ali, Yacob (Kuwait Oil Company) | Wang, Guojuan (Kuwait Oil Company) | Al-Mula, Yousef (Kuwait Oil Company) | Hussein, Mahmoud (Kuwait Oil Company) | Choudhary, Pradeep (Kuwait Oil Company) | Ahmed, Fatma (Kuwait Oil Company)
There are two ongoing steamflood pilots with inverted five-spot, 5-acre and 10-acre spacing patterns in North Kuwait heavy oil field. KOC determined that performing two or three Cycle Steam Stimulation (CSS) cycles followed by steamflood is required to achieve the production target from a multi-layer reservoir with two vertically separated heavy oil zones.
A previous reservoir simulation study identified two possible completion strategies. One completion strategy for simultaneous steaming in the 5-acre spacing pattern and the other completion strategy for steaming one zone at a time in the 10-acre well spacing pattern.
In this paper, we discuss for the two pilots, operational and monitoring challenges and the substantial difference in the performance after first CSS cycle for the two well completion strategies.
The Steamflood pilots are currently at the pre-flood stage and the first cycle of the Cyclic Steam Stimulation (CSS) has been finalized. A comprehensive reservoir and well surveillance program is being conducted to monitor and gather data necessary to better understand the reservoir and well performance in the pilots.
One of the goals of the pilots is to use the acquired reservoir understanding to determine a completion strategy for commercial development of the field from two options identified in the reservoir simulation study. This paper presents insights on the difference in the performance with the two well completion strategies.
The first CSS cycle in the wells with 10-acre spacing and the completion strategy for steaming one zone at a time demonstrated relatively better performance compared to the wells in the 5-acre pilot with a completion strategy for simultaneous steaming where more challenges were observed.
The reservoir properties and field surveillance data were used to explain this performance difference for the two well completion strategies after first cycle of CSS.
The recommendations and conclusions in this paper are based on actual field data in a multi-layered heavy oil reservoir after the first CSS cycle. Future papers will present the results after further CSS cycles and steam flooding.
Gonzalez, S. (Kuwait Oil Company) | Al-Khamees, Waleed (Kuwait Oil Company) | Abdalla, A. W (Kuwait Oil Company) | Rajab, S. Y. (Kuwait Oil Company) | Fadul, I. (Schlumberger) | Jama, A. (Schlumberger) | Hamlaoui, A. (Schlumberger)
The Large Scale Steam Flood Pilot with two patterns in South Ratqa Field (Heavy Oil – North Kuwait) is considered the first of its kind in KOC and a major milestone for North Kuwait (NK) Heavy Oil Development program. The pilot program is crucial for NK Heavy Oil development plans as it will allow the evaluation of the Lower Fars Heavy Oil reservoir at close spacing, and it will assess the implication of the selected recovery process for South Ratqa (SR) field operations and project economics. In addition, the project will enable NK to: Optimised production of Heavy Oil reserve through Steam Flood Assess well completion integrity and optimum A/L type Identify Cost optimization opportunities for Heavy Oil phased development
Optimised production of Heavy Oil reserve through Steam Flood
Assess well completion integrity and optimum A/L type
Identify Cost optimization opportunities for Heavy Oil phased development
The two patterns test different schemes, one for the evaluation of 10-Acre spacing with the second for evaluation of 5-Acre spacing with inverted five spot configurations. The 10-Acre pattern consists of 13 wells (Producer/Injector) plus 7 observation wells; the 5-Acre pattern consists of 13 wells (Producer/Injector) plus 4 observation wells. All observation wells are equipped with Distributed Temperature Sensing (DTS) systems. Furthermore, for the first time in KOC, all wells are equipped with the thermal wellhead stack up to allow operations while injecting or prodcing. This will greatly save time, rig cost and minimize workover interventions.
Production and Reservoir engineers frequently use allocated volumes to estimate current production volumes from wells based on frequent well test data or theoretical calculations using well and reservoir characteristics.
The KOC Heavy Oil asset deployed a production data management system (PDMS) from early days of Large Steam Thermal Pilot North (LSTPN) production to establish a scalable and reliable workprocess among the organisation. The production and operations data management system manages steam injection, soaking and the production phases through data collection, quality control validation and production back allocation as well as shortfall analysis for planned and unplanned downtime events.
The new system provides main checks for the steam injection and emulsion production streams, track gathering systems functionality through time, derive the allocation networks, and produce internal and external reports.
Haghighi, M (The University of Adelaide) | O'Reilly, DI (Chevron Australia Pty Ltd, The University of Adelaide) | Hunt, AJ (Chevron Australia Pty Ltd) | Sze, ES (Chevron Australia Pty Ltd) | Hopcroft, BS (Chevron Australia Pty Ltd) | Goff, BH (Chevron Australia Pty Ltd)
This paper demonstrates how good technical evaluations and focused operational application can enhance the value of a mature asset. The Windalia reservoir underlies Barrow Island (BWI), situated 56 km from the coast of Western Australia, and has produced oil since 1965. Waterflooding commenced shortly after initial production, in 1967, and remains the main drive mechanism in the field today. Throughout the life of this onshore field, water injection and oil production have varied according to asset strategy and economic conditions. In this case study, we share how recent improvements made in the areas of Reservoir Surveillance and Operations activities have increased water injection efficiency and total oil recovery.
Through the use of new methods and workflows, the BWI Sub-Surface team was able to target specific areas of the field to distribute water to in order to increase injection and maximise oil production. For example, new workflows were built with the real-time PI monitoring system to analyse Pressure Fall Off (PFO) tests from each of the 147 waterflood patterns in detail. Capacitance-Resistance-Modeling was also leveraged to guide individual well target injection-rates. Operationally, several projects were also initiated to increase water injection into the right areas of the field.
The new Reservoir Management approach has significantly increased the volume of water being injected into the areas of need, supporting improved levels of oil production. For the first time in almost 10 years, the stream-day water injection rate has exceeded 90,000 bwipd. The results from PFO transient interpretation and pattern balancing proved effective in directing water to low-pressure, high-GOR areas of the field. They also provided valuable information about formation perm-thickness and skin. The phenomenon of water-cycling was also largely avoided, owing to close monitoring of production well tests and water injector transient surveys.
The present work addresses reservoir and operational aspects of Australia's largest active waterflood. The lessons shared are highly applicable to a low oil price environment, as they show how fit-for-purpose and low-cost acquisition of reservoir data can lead to improved field performance.
Unconventional reservoirs, due to their complexity, are among the greatest challenges to the oil and gas industry. After years of research, shale gas and tight gas reservoirs are now proven to be one of the unconventional reservoirs that are economically viable to fulfill the crucial energy requirements. Due to their low permeability and several other factors, they require advance techniques on both operational and simulation fronts.We performed several different simulations, both numerical and analytical, covering a variety of scenarios to compare shale gas and tight gas production forecasts. Both vertical and horizontal completions were analyzed. For horizontal completions, different hydraulic fracturing stage density was evaluated to identify the best possible production profile for a well and the entire field. The simulations show that Langmuir pressure, volume, rock density, well spacing, completion type, lateral length, and reservoir thickness have a large effect on production forecasts as well as simulations. The simulation results also show the effect of permeability in different cases. The aforementioned are key factors in development plan for a shale gas asset. All the values used for forecasting, both numerical and analytical, are typical for worldwide shales and belong to open source data. They have been selected carefully due to their close resemblance to unconventional reservoirs in Pakistan.
Horizontal wells with multi-stage hydraulic fracturing have dramatically boosted Eagle Ford production since 2008. Due to the high drilling and completion costs, compared to the wells with conventional drilling and completion, operators have been trying to improve development economics by understanding unconventional plays and optimizing stimulation treatments using various data analysis techniques. In this paper, the multivariate regression analysis method is used to evaluate the Eagle Ford production and completion data for wells within 3-5 years' production as a means to determine the correlations of production performance with completion and other variables. A ‘big-picture' view with 174,000 acres were initially chosen for the study, where 487 wells were selected in the portion of the Eagle Ford oil "window?? located in Karnes and Live Oak counties. 2D heat maps and 3D plots were applied to illustrate the correlation and the relative importance of each variable. Among 487 wells selected for data evaluation, only 273 wells were used for the multivariate regression analysis due to the data incompleteness for some of the wells. In the data analysis and multivariate regression analysis of this paper, it was demonstrated that the proppant tonnage and horizontal lateral length are not the most important variables affecting the early-time production in the study area, as may be expected by many engineers. We have nine (9) variables selected for this study. Those variables (proppant tonnage and horizontal lateral length) are generally less important than formation depth and tubing flowing pressure. However, frac fluid amount shows importance in the gas condensate area, between reservoir depth between 12,000 to 12,500 ft. In the same depth region (12,000 to 12,500 ft), the proppant tonnage and horizontal lateral length don't correlate with production well in the region of (2000 - 5000 tons of sand and 2000 - 6000 ft of lateral), meaning that this could be the water frac candidate area (more water, less proppant). They may even be less important than fluid properties (gas oil ratio (GOR) and oil API gravity, which are related to oil viscosity). Approximate linear relationships of early-time production vs. tonnage or lateral length could be observed when a well group is selected in a small area where the geological, petrophysical, reservoir and fluid properties are nearly constant. Optimizations of proppant tonnage, lateral length and/or frac fluid amount may be performed based on the relationships.