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In this work we present the evaluation of field scale commercial miscible EOR for a giant offshore carbonate reservoir. The current assessment leverages the prior multi-year evaluation assessing the attractiveness (‘do-ability’) and prize for miscible EOR within each geologic area and reservoir within the field.
Two geologic areas, the "heterogeneous" and "homogeneous" geologic regions of the Crestal area in the largest reservoir were identified as the primary targets for field scale miscible EOR based on the prior multi-year assessment and are the focus of the current assessment. Commercial field-scale miscible development is predicated on a 1-to-1 line drive waterflood with 1km spaced extended reach horizontals with 10,000 ft completions and 500m spaced infills in the more heterogeneous area of the field.
Given the offshore environment, base development utilizes four artificial islands which support facilities for field development and serve as drilling centers. Commercial development with miscible EOR will be implemented in a ‘phased’ (staged) approach where the initial developments will be from the Central Island in the late 2030s followed in succession by the South Island in the early 2040s and North Island in the 2050s.
This assessment uses a novel phased approach where a ‘Tapered WAG’ scheme is used. By utilizing a phased (‘staged’) approach, multiple development concepts can be evaluated expediently. In this work we (i) show an efficient field assessment process for miscible EOR, (ii) illustrate how subsequent patterns can be brought on-line over time as part of a Tapered WAG process and (iii) demonstrate the importance of commercial assessment as part of field development planning and pilot assessment.
The full field assessments included here allows multiple development strategies to be assessed expediently and facilitates the selection of an injection solvent (hydrocarbon gas or CO2). Full field economics have been completed and hydrocarbon gas has been identified as the target solvent. Hydrocarbon gas has the benefit of being commercially attractive and is compatible with existing facilities. Currently two pilots are in preparation to assess the incremental recovery beyond waterflood and assess the commerciality of miscible EOR in a giant offshore carbonate reservoir. Key learnings in this paper include (i) an efficient methodology to assess phased field development for miscible EOR, (ii) incremental recovery of miscible EOR beyond waterflood, (iii) metallurgy and facility requirements for the two solvent schemes and (iv) a preliminary assessment of field scale commerciality including economics for the two solvents, hydrocarbon gas and CO2.
Identification of hydrocarbon generating source rocks and evaluation of their potential are essential in the exploration and development of hydrocarbon resources. For an offshore oil field in Abu Dhabi, we conducted geochemical study using crude oil and core samples from Upper Cretaceous Cenomanian carbonate rocks. The study objectives are 1) correlation of crude oil and source rock with biomarker, and 2) evaluation of the source rock potential.
The Cenomanian carbonate rocks of the oil field are composed of shallow marine porous limestone and deep marine lime mudstone. This Cenomanian lime mudstone was believed as source rock of the crude oil in the interfingered Cenomanian porous limestone reservoirs. However, the origin of crude oil has been poorly constrained with geochemistry yet. In this study, we carried out geological description and RockEval pyrolysis analysis of core samples to evaluate source rock potential of the lime mudstone. Then, biomarkers such as hopane, sterane and compound specific isotopic ratio of n-alkane were analyzed to correlate the source rock and the crude oil samples with GC/MS, GC/MS/MS and GC/C/IRMS for high resolution biomarker measurements and robust interpretation.
As a result, the biomarker fingerprints of the crude oil in porous limestone and the organic material in the lime mudstone show significant similarity. It proves that the crude oil in the porous limestone is migrated from interfingered organic rich Cenomanian lime mudstone. In addition, the lime mudstone shows excellent source rock property (Total Organic Carbon exceeding 4%, Hydrogen Index > 600mg/g TOC) and categorized as Type I/II source rock deposited in marine environment. Furthermore, the biomarkers effectively constrain the maturity of source rock which is difficult to evaluate with Vitrinite Reflectance and RockEVAL analysis. Consequently, the timing of hydrocarbon generation and the area of effective source rock will be interpreted based on our study result with higher confidence.
This study deepens understanding of Cenomanian petroleum system in offshore Abu Dhabi. The result suggests the advantage of biomarker application not only in oil-source correlation but also in source rock maturity analysis.
This paper presents a case of study of cementing operations in extended reach drilling (ERD) wells on two artificial islands in UAE. The cementing objectives involved covering and isolating the shallower oil or water-bearing zone, sealing any potential crossflow interval between various reservoirs, and mitigating communication between the 13 3/8-in × 16-in. and 9 5/8-in × 12 ¼-in. annulus. Additionally, the cement will become a secondary barrier planned for the 9 5/8-in. casing to prevent potential exposure of the 13 3/8-in. casing in the event of injection gas percolation. For this case was necessary to design the cement with the necessary mechanical properties to extend the well life expectancy.
To accomplish the operation objectives, the formations, well design complexity, and possible complications were considered. Understanding these factors facilitated the improvement in the approach and design to obtain better cementing operations results. To achieve all of the targets, various enhancements were implemented systematically over time, which included adding fiber in the cement spacer to mechanically enhance mud removal, adding corrosion inhibitor and bactericide to protect the casing if fluid remained in the well. Various lead cement slurries were designed with tailored rheology to remain within the established narrow margin between the pore pressure and fracture gradient. A flexible and expandable tail cement slurry system was implemented to increase the likelihood of proper isolation. The expansion of the tail cement slurry after the cement sets and the tailored mechanical properties used to achieve the necessary resilience, provide support for the stresses encountered during the life of the well. Upgraded properties, such as fluid loss, reduced permeability, and static gel strength (SGS) development, were used to mitigate possible influx between formations. Both cement slurries were loaded with resilient fiber to enhance the cement ductility. These strategies combined with software simulations enabled equivalent circulating density (ECD) management, contamination avoidance, friction pressure hierarchy, discernment of the top of cement (TOC), determination of possible channels, and appropriate stand-off design.
The application of the solutions combined with outstanding consistent field operational performance enabled the following: Fine-tuning various practices, improving isolation across critical zones, achieving the planned TOC, sealing the formations that could create potential future issues, and reducing the probability of interzonal communication or crossflow. A systematic approach was necessary to achieve all the objectives in these challenging wells and determine which practices and technologies provide the appropriate results.
Cementing ERD wells with the challenges previously described is not a standard industry practice. This case study presents the staged application of the enhancements that improved the cementing results. These were inferred by evaluating the operational parameters (density, pumping rate, pressure, volumes, and surface returns) in conjunction with the availability of cement logs (CBL, VDL, ULTRASONIC). The results demonstrated the capability to achieve isolation; Furthermore, the continuous annulus surveillance showed no undesirable sustained casing pressure.
Mahamat Habib, Abdelkerim Doutoum (ZADCO) | Al Katheeri, Yousif Saleh (ZADCO) | Seales, Sheldon (ZADCO) | Ramdeen, Rayaz Evans (ZADCO) | Bermudez, Romulo Francisco (ZADCO) | Navas, Luis Eduardo (ZADCO) | Kapoor, Saurabh (Schlumberger) | Pallapothu, Surya (Schlumberger) | El Hassan, Azza (Schlumberger) | Jain, Bipin (Schlumberger)
Achieving well integrity relies on achieving zonal isolation among narrowly separated sublayers of the reservoir throughout a long openhole section. This requires flawless primary cementation with a perfect match of optimized fluid design and placement.
In a UAE field, there are several challenges experienced while cementing production sections, predominantly due to long open holes with high deviation, use of nonaqueous fluids (NAF) for shale stability, and loss circulation issues while drilling and cementing. The need to pressure-test casing at high pressures after the cement is set and the change in downhole pressures and temperatures during well completion / production phases result in additional stresses that can further endanger the integrity of the cement. Breaking of the cement sheath would lead to sustained annular pressure and compromise the needed zonal isolation. Hence, the mechanical properties for cement systems must be thoroughly tested and tailored to withstand the downhole stresses.
A systematic approach was applied that used standard cementing best practices as a starting point and then identified the key factors in overcoming operation-specific challenges. In addition to the use of engineered trimodal slurry systems, NAF-compatible spacers, and loss-curing fibers, an advanced cement placement software was used to model prejob circulation rates, bottomhole circulating temperatures, centralizer placement, and mud removal. To enhance conventional chemistry-based mud cleaning and to significantly improve cleaning efficiency, an engineered fiber-based scrubbing additive was used in spacers with microemulsion based surfactant. Furthermore, a real-time monitoring software was used to compute and monitor equivalent circulating density (ECD) during the cementing operation and to evaluate cement placement in real time. Results of cement jobs were analyzed to define the minimum standards/criteria and then to verify the efficiency of the applied solutions.
The 9 5/8-in. casing / liners were successfully cemented using this methodological approach, and lessons learned were progressively used to improve on subsequent jobs. Advanced ultrasonic cement bond logging tools along with advanced processing and interpretation techniques facilitated making reliable, conclusive, and representative zonal isolation evaluation. The cement bond logs showed significant improvement and increased the confidence level towards well integrity.
After establishing field-specific guidelines over 2.5 years, continuous success was replicated in every well for all the rigs operating in this UAE field.
The subject field is a giant offshore reservoir with light oil and a planned long production life extending beyond 100 years. In order to sustain oil production, EOR will be implemented at the appropriate time. As a result of EOR screening, miscible water-alternating-gas (WAG) injection was identified as one of the suitable methods. In order to evaluate miscible WAG potential, extensive WAG simulation studies were conducted in each step including 1D, 2D and 3D simulation.
First, 1D simulations were conducted for tuning the equation of state (EOS). Second, 2D conceptual model simulations were carried out for the preliminary evaluation of WAG. Then, 3D conceptual models for two typical geological areas of the subject reservoir, the "Homogeneous" and "Heterogeneous" geologic areas were generated and findings from the 2D simulation study were validated. Finally, 3D sector model simulations were conducted using the history-matched simulation model to evaluate the miscible WAG potential for full field implementation and its economics. In all simulation studies, CO2 and hydrocarbon (HC) gas were evaluated as miscible injectants.
1D simulations replicated a slimtube test and EOS parameters were tuned to match the minimum miscible pressure (MMP) of CO2 and HC gas. As a result of 2D simulations, "Tapered" WAG appears the most attractive WAG injection scheme in terms of gas utilization and oil recovery. In the Tapered WAG concept, the durations of gas injection varies where longer gas injection cycles are completed initially progressing towards shorter gas injection cycles with progressive WAG sequences. The Tapered WAG concept was also tested using the 3D conceptual model and similar findings were obtained. To evaluate miscible EOR WAG for the full field, due to the size of our field, the high resolution gridding required to capture fluid transport and the 9 component tuned EOS, the required computing resources exceed typical computing capacity; hence, two sector models which represent the Homogeneous and Heterogeneous areas were generated. Based on simulation results, normalized type curves for the hydrocarbon pore volume injected (HCPVI) with incremental recovery factor were generated for each geological area. A production and injection profile for full field WAG implementation was generated by applying these type curves to each pattern and incremental oil production was estimated.
The potential incremental oil production for WAG application for a giant offshore oil field was successfully assessed utilizing extensive simulation scenarios from a preliminary concept using simplified models to a detailed full field analysis using complex models. Through this step-by-step analysis, we were able to efficiently identify the key criteria impacting full field recovery including Tapered WAG, impact of injectant and impact of multi-scale heterogeneity (e.g. 2D-3D).
To sustain the long term production from a giant offshore reservoir, a simulation study evaluating and comparing miscible hydrocarbon (HC) Water-Alternating-Gas (WAG) with a prior pilot test implemented in the field evaluating immiscible HC Simultaneous Water-And-Gas (SWAG) has been carried out. This paper describes the evaluation of recovery uplift for the miscible HC WAG by comparing study findings with actual field results for the immiscible HC SWAG pilot.
In order to evaluate miscible HC WAG potential, sector model simulation studies were carried out and it was concluded that a 11% recovery uplift over base water injection could be achieved by miscible HC WAG. On the other hand, an analysis of the immiscible HC SWAG pilot test including history matching simulation was conducted and it was concluded that immiscible HC SWAG had little impact on recovery uplift. In order to evaluate the differences between the planned miscible HC WAG implementation and the immiscible field pilot test results, the comparative investigation was conducted using sector model.
The area where the immiscible SWAG pilot was conducted was geologically similar to the target area for the miscible WAG. To confirm the geological similarity of the two areas, simulations for immiscible injection using a 5-spot configuration consistent with the immiscible SWAG pilot were carried out for each area. Results indicated gas distribution was similar in the two areas and was in agreement with actual pilot results; hence, it was confirmed that the impact of geologic differences of the two areas was limited. The other differences between the planned miscible HC WAG and the immiscible SWAG pilot were (i) injection scheme (WAG or SWAG), (ii) well configuration (line drive or 5-spot pattern), (iii) well spacing (500 m or 1 km) and (iv) injectant (miscible HC gas or immiscible HC gas). Simulation models capturing each scheme were developed. Through the injection scheme sensitivity simulation studies, it was concluded that (i) WAG, (ii) line drive, (iii) 500 m spacing and (iv) miscible HC gas were preferential to (i) SWAG, (ii) 5-spot pattern, (iii) 1km spacing and (iv) immiscible HC gas, respectively. The combination of these factors resulted in a 21% recovery uplift beyond the prior immiscible HC pilot. Hence, through this work we demonstrate that a reliable evaluation for recovery uplift with miscible HC WAG was achieved through the comparative investigation of the immiscible HC SWAG field pilot test results and the planned miscible HC WAG implementation, including the analysis of the impact of geology, injection scheme and well configurations.
Drilling and Completions operations optimization requires as starting point the building of an alive database that sustains the benchmark for a list of defined KPIs. The KPIs will represent main well construction activities conducted in different well types in a specific field. Once the data is captured and processed, the operations efficiency is obtained with the computation of the Invisible Lost Time (ILT). Computations are defined in different ways by different operators with different margins. The purpose of this paper is to probe that operational efficiency that can be tracked better when the percentiles lead the targets and not the Composite Best as a target.
The continuous monitoring of the performance and the daily distribution of KPI's tracking dashboard has changed the mindset of the entire team, engaging the rig personnel in the identification of specific limiters that affect the performance and defining specific actions to take to revert the trend. The year to year comparisons showed a significant performance improvement in all the rigs but not at the same rate. The expected learning curve has deferred from one rig to another.
A forecast tool has been created to generate an automatic AFE that delivers automatically TvD curves for the different percentiles and it is aligned to the latest rig's performance and the well architecture. This tool will help the drilling engineers to estimate, quick and more accurate, the well duration time, especially when the rig allocation is crucial for the yearly objectives of the project.
Obeta, Chukwudi (ZADCO) | Aljaberi, Fatema (ZADCO) | Khouri, Naeema (ZADCO) | Al Zawa, Hesham Abdulla (ZADCO) | Wendland, Corey (ZADCO) | Dedmon, Russell (ZADCO) | Al Dhaleei, Omar (ZADCO) | Ottinger, Gary (ZADCO) | Shekhar, Ravi (ZADCO) | Omura, Taihei (ZADCO) | Al Zinati, Osama (ZADCO) | Abousayed, Nada (ZADCO) | Almurshidi, Saja (ZADCO) | Khan, Mohammad Yunus (ZADCO) | Attalah, Khaled (ZADCO) | Al Neyadi, Abdulla (ZADCO) | Al-Shehhi, Budoor (ZADCO)
As part of the ongoing development of a large offshore oil field, an asset owner places a strong emphasis on continuous improvement of the established framework for integrated post-drill well analysis. The geology of the candidate field is complex and the occurrence and distribution of the extreme permeability features that dictate early water production is highly uncertain. While much effort is devoted to mitigating their adverse impact through proper integration of surveillance data for accurate well planning, post-drill outcomes can still diverge significantly from pre-drill expectations. Several wells have been drilled in the production build-up campaign, including ground-breaking pilots and many more are following in very quick succession as part of the life cycle strategy for the field. Due to high drilling frequency, the challenges of assimilating learnings through conventional post-drill analysis for optimization of future drill wells can be enormous. To apply key lessons from these wells in building quick baseline knowledge for reservoir model update and drill plan optimization, the modeling and development team have developed an improved workflow for integrated post-drill analysis. The workflow leverages the full benefit of collaboration between multi-disciplinary teams to integrate 3D seismic data, multiple well information (including geologic reports, well logs and petrophysical results) and surveillance data from new drill wells to benchmark pre-drill expectations. An important aspect of the approach is the quick incorporation of drilling results into static and dynamic models via a cycled, closed-loop workflow for quick assessment of model fidelity through an evergreen update process. A multifunctional post-drill analysis facilitates critical consideration of well results to capture significant learnings that influence future drill well and data acquisition optimization, reservoir model history match and prediction enhancements, and identification of drilling hazards and geological features that affect reservoir performance. This paper describes the methodology used to plan and implement post-drill well analysis within a fast paced and high drill frequency environment. Key elements of the methodology are described through the use of a case study example, and include: Standardized subsurface workflow, comparison of post-drill well results with pre-drill well expectations, identification and documentation of significant observations and lessons learned improvement of history match & predictive capability of reservoir models and integration with other drill-well delivery processes.
Recent advances in satellite technology such as improved image resolution and use of multi-spectral bands have increased its potential as an alternative source of hydrographic data. Recent applications in the surveying industry have proved the usefulness of Satellite Derived Bathymetry (SDB) as a low cost source of good quality bathymetry data. In order to support ADNOC's efforts to fast track new field development projects and timely delivery of high value data, ZADCO as part of its survey campaign selected SDB as a tool to source quality near shore hydrographic data.
Offshore bathymetry derivation was realized using WorldView-3 satellite scenes. These scenes were processed by following a rigorous processing methodology for the correction of atmospheric adjacency. The processed and corrected satellite image provided a spatial resolution of nearly four metres and covered depths from the 0m depth contours up to the 15m depth contours. The accuracy and reliability of the satellite images are dependent on the optical conditions of the satellite scene, the sensitivity of the satellite's sensor and the accuracy of the calibration.
After detailed multi-level quality checks for various systematic and non-systematic errors, the most reliable bathymetry that was found to meet ZADCO selection criteria was noted to be between 0m and 3m water depths, with an error of ±0.3m. Water depths between 3m and 5m presented themselves with an error of ±0.4m, whereas for depths between 5m and 10m, the errors varied between 0.5m to 1.0m. It was found that in the extreme nearshore areas with depths between 0m and 3m water depths, SDB could be accepted for use as it was falling within the tolerance limits of ±0.3m, with most areas having a tolerance of ±0.2m. While satellite derived bathymetry between the 0m to 5m water depths was found to be of acceptable quality, those over drying heights were found to be completely unreliable.
The reliability factor that could be established for SDB data between 0m and 3m implied that dangerous and logistically challenging nearshore survey operations using conventional methods, that is, using shallow draught survey motor boats could be done away with. This also presented an interesting corollary in that it can also remove a huge HSE risk factor associated with shallow water survey boat operations, which are otherwise a significant risk due to the presence of underwater obstacles such as corals, rocks, reefs and surface dangers such as wave action and tidal influences.
In conclusion, high resolution multi-spectral satellite imagery corrected for atmospheric and underwater refraction effects combined with the correct processing techniques and multi-level quality control mechanism provides a reliable source for bathymetry in extreme nearshore areas. Based on the results achieved it was concluded that SDB data can be used for engineering planning and estimation applications, for quick turnaround.
Pipeline routing being one of the crucial activities of pipeline design, significantly affects almost every other aspect of the design process. Seabed terrain at many locations in Arabian Peninsula and other parts of the world is revealed to be rough & undulating which sometimes presents a significant challenge in routing the pipeline. The common challenges for pipeline routing on the rough seabed terrain can be identified and evaluated using the advanced tools at early stage of the design to select an optimized route. Figure 1 depicts the examples of pipeline routing on the rough seabed.