The Haft Kel field is located in Iran. Its Asmari reservoir structure is a strongly folded anticline that is 20 miles long by 1.5 to 3 miles wide with an oil column thickness of approximately 2,000 ft. The most probable original oil in place (OOIP) was slightly 7 109 stock tank barrels (STB) with about 200 million STB in the fissures; numerical model history matching resulted in a value of 6.9 109 STB. The matrix block size determined from cores and flowmeter surveys varied from 8 to 14 ft. The numerical simulation model considered matrix permeabilities from 0.05 to 0.8 md.
It has approximately 5.9 billion bbl of stock tank original oil in place (STOOIP) and covers more than 200 sq. The sandstone reservoir consists of two zones [A (62% of STOOIP) and C (38% of STOOIP)] that are separated by impermeable shales and siltstones. Sales oil is approximately 24 API with a viscosity at reservoir conditions of approximately 2.5 cp. The reservoir oil was approximately 300 to 500 psi undersaturated at the original reservoir pressure of approximately 3,300 psia. The reservoir is broken into segments by several north-to-south faults (density of approximately three faults per mile) that have sufficient throw to totally offset adjacent portions of the reservoir.
One of the world’s leading energy watchers says the second shale revolution will come in the form of LNG exports. After 70 years of production, more than 30% of the Arab C reservoir stock-tank original oil in place has been recovered through various mechanisms including natural depletion, waterflooding, gas lift implementation, and horizontal-well development. The North field offshore Qatar was observed to have a chance of inner annuli becoming charged with shallow-gas pressure with possible communication to other annuli, which was thought to be a well integrity concern. Airborne imaging spectroscopy has evolved dramatically since the 1980s as a robust remote-sensing technique used to generate 2D maps of surface properties over large areas.
In Malaysia, and similarly worldwide, there are numerous brownfields with the potential to increase recovery via water injection (WI) as the secondary recovery mechanism. Currently, Malaysia has 27 WI fields that account for only 39% of discovered Stock-tank Oil Initially in Place (STOIIP) but contribute significantly up to 55% of total Malaysian production. Water injection activities are increasing despite the technical and commercial challenges, especially for marginal or stranded fields. With the tremendous experiences from oil and gas companies of managing WI fields, it is time to capture and share the additional value and knowledge within the industry for all to achieve ‘best in class’ operator status. The key in managing water injection is to look at a molecule to molecule (M2M) concept that encourages a wholesome and integrated approach in resolving challenges in existing and upcoming WI fields.
Special Core Analysis, SCAL data has a direct impact on the way fluids are allocated and distributed in the reservoir simulation models, which would directly impact reservoirs’ STOIIP estimation and their distribution. Moreover, it directly affects the performance of secondary and EOR flooding processes, and in turn impacts the accuracy of the oil and gas reserve estimates, and the management of these reserves. Therefore, SCAL data could be considered as one of the most critical reservoir input data for reservoir simulation models. This course will shed light on the theoretical and experimental background of SCAL data. It will explain the concept of reservoir wettability and different factors that could induce changes in reservoir wettability.
The Bakken Petroleum System, which includes the Bakken and Three Forks shales in North America, is estimated to hold as much as 900 billion bbl of original oil in place. However, the technically recoverable oil is a fraction of the total, estimated to be 20 billion bbl to 45 billion bbl, because most of the 8,000 producing wells have a recovery factor of about 3% to 10%. "And in fact, 10% is anomalously high," said James Sorenson, a senior researcher at the Energy & Environmental Research Center (EERC). "So it is clear with the enormous size of the prize in the ground that even small improvements in recovery could yield significant amounts of oil." Sorenson is leading a research project involving government agencies and several upstream companies in search of a way to squeeze more oil out of the Bakken for years to come by using CO2 for enhanced oil recovery (EOR).
Determining the remaining spatial oil-saturation distribution or current reservoir-pressure distribution for a mature (water, solvent, CO2) flood is a cornerstone of reservoir management for improving sweep and selecting infill-well locations. Decisions of these types are typically supported by reservoir flow simulation models that have been calibrated to historical injection/production data.
In this paper, we present a novel-pattern material-balance (PatMB) approach to estimating remaining fluids in place as an alternative to flow simulation. First, we use the historical injection/production volumes to solve for streamlines and streamline-derived pattern metrics such as well-allocation factors and injector/producer-pair reservoir pore volumes (PVs). Then, we apply material balance on these volumes over time to estimate the remaining oil in place (ROIP) and pressures at the end of history. Resembling reservoir simulation, the method considers changing well patterns through time, requires a 3D static geological model, and yields 3D saturation distributions of oil, water, and gas. However, unlike reservoir simulation, because historical injected and produced volumes are used directly, calibration is only possible through the 3D distribution of PV and fluids initially in place.
We present results for the Berrymoor-pattern waterflood and show that the ROIP distribution is a strong function of the original-oil-in-place (OOIP) distribution, well locations, and historical oil, gas, and water production/injection volumes. For this case, the ROIP distribution is almost insensitive to interwell permeability distributions, suggesting that the primary focus when estimating ROIP with the PatMB approach is to ensure a good estimate of OOIP, major flow units, and the correct injection/production data. We also compare our method to reservoir flow simulation for a large water/hydrocarbon miscible flood (HCMF), and we observed that the ROIP maps compare well, with both methods highlighting similar areas for potential infill locations. However, the remaining-gas-in-place maps differed with PatMB, showing a more diffused distribution than flow simulation of the gas. We attribute the difference to the fact that PatMB does not account for transport effects such as separation of the phases caused by density differences.
Several surfactant formulations that had been tested successfully in oil-wet unconventional reservoirs were tested in mixed-wet to oil-wet unconventional reservoir cores and did not generate the expected results. To study the mechanisms of oil recovery and understand the uniqueness of these shale reservoirs, a series of studies were performed utilizing Eagle Ford (EF) and Canadian Bakken shale rocks and fluids.
In this study customized chemical formulations for improving production from the EF and the Canadian Bakken were developed. Previously related formulation development for the Bakken and Permian basins relied upon wettability alteration as the oil recovery mechanism; however, no significant oil recovery compared to brine was seen from wettability-altering formulations using EF and Canadian Bakken shale rock and fluids. Several imbibition tests showed that baseline oil recovery by brine was 20-30% of original oil in place (OOIP) for both formations. High oil recovery by brine was attributed to the mixed to water-wet nature of the pore surface. A well-connected fracture system may have also contributed. Further, there was no correlation between oil recovery and contact angle measurements.
Failure of wettability alteration as an oil recovery mechanism led to investigation of interfacial tension (IFT) reduction as an alternative mechanism. Testing this hypothesis, a change in the EF formulation reduced IFT to 0.03 dyne/cm and had oil recoveries above 60% OOIP. However, these formulations were not stable at 320 °F. Formulation KPIs were set as lowering IFT and being stable up to 320 °F. Out of many formulations tested, two containing multiple actives in a specific mixture of solvents passed the KPIs and were tested for imbibition oil recovery. A synergistic mixture had a final oil recovery above 56% OOIP as compared to 20-25% OOIP for brine alone. The imbibition oil recovery results indicate that although the ultimate oil recovery by brine alone is significant, the early oil production is significantly slower than by surfactant solutions. Upscaling the laboratory time to the field time emphasizes the value of implementing customized surfactant formulation in both early and late oil production.
Similarly, there was no correlation between wettability contact angle measurements and oil recovery for the Canadian Bakken shale. Surfactant formulations which exhibited low IFT (~0.01 dyne/cm) significantly accelerated the oil production and recovered an additional 30-45% OOIP in the tertiary mode from the imbibition tests. Further laboratory studies via the Washburn method, imbibition tests, and zeta potential measurements validated lowering IFT, not altering the wettability, as a primary oil recovery mechanism in the mixed-wet EF and Canadian Bakken.
Optimal formulations for EF and Canadian Bakken will be tested in the field by mid-2018.
Elfeky, Mohamed Helmy (Abu Dhabi Marine Operating Co.) | Al-Neaimi, Ahmed (Abu Dhabi Marine Operating Co.) | Yousef, Omar (Abu Dhabi Marine Operating Co.) | Al-Hosani, Ibrahim (Abu Dhabi Marine Operating Co.) | Iwama, Hiroki (Abu Dhabi Marine Operating Co.) | Farhan, Salman (Abu Dhabi Marine Operating Co.) | Seoud, Abouel (Abu Dhabi Marine Operating Co.) | Channa, Zohaib (Abu Dhabi Marine Operating Co.) | Khemissa, Hocine (Abu Dhabi Marine Operating Co.) | Khan, Muhammad Navaid (Abu Dhabi Marine Operating Co.)
Facing a well control issue while drilling multi reservoirs with different reservoir pressure is very common in oil field worldwide, each and every engineer who is involved in the operations is dealing with this issue on daily basis. However, if the unexpected high pressure is observed while drilling a matured reservoir with known pressure, it is always a challenge to identify the source of the problem and to define the efficient remedial action plan, without compromising the well deliverables. The case study presented in this paper is related to a workover of a well in a giant offshore field in Abu Dhabi, where abnormally high pressure encountered while drilling the reservoir section with little amount of flow into the wellbore. Identifying the source of discrepancy and to establish the mitigate plan without impacting Well's Workover/Drilling duration was a serious challenge. What made the situation more complicated was the high risk of water in the heel section of 6" horizontal drain, which was prone to shorten the well life significantly. This paper will introduce an efficient novel solution to use 4 ½" casing liner in a certain configuration, consisting of the mechanical and the Swellable packers to cure the cross communicating reservoirs (source of abnormal high pressure); and isolate the risky heel section of the well, to extend well life without impacting the planned well duration. This work will also describe the process of identifying the source of pressure, selecting the most suitable well completion strategy to meet the well objectives successfully. Moreover, it will also shed some light on the need of using reservoir simulation technique to assess different well completion options. Finally, the paper will be concluded with methodology on how to save time and cost whilst changing plans to cope with the unforeseen issues.
The Kelly-Snyder field is the largest of a chain of fields along the Pennsylvanian Horseshoe atoll in the Midland Basin. Within this field, the Scurry Area Canyon Reef Operators Committee (SACROC) Unit covers approximately 56,000 acres with 2,800 million STB of original oil in place (OOIP). Limestone is the dominant mineral within the Canyon Reef formation, and less than 3% of the formation exists as thin sections of shale (1–10 ft in thickness) that are important stratigraphic markers.