The challenges of high heterogeneous multi-layer reservoirs were a driver for ADNOC to establish new well completion requirements. Based on this, the well completion strategy was revised in order to improve the completion design for a Dual Oil Producer (DOP) initially well planned without accessibility into the upper drain. The solution was successfully implemented by drilling the well having a Multilateral Dual String Level 5 Completion System to have full reservoir isolation and mechanical accessibility to TD in both drains. A major approach was implemented giving the utmost importance to all operational risks concerning drilling and completion. The design relies on the Latch Coupling (LC) pre-installed with the production casing as the foundation for the successful drilling and cementing the upper drain liner and for different completion runs. Thus, a level 5 multi-lateral completion coupled with Inflow Control Devices and Pre-perforated Liner in the upper and lower lateral respectively was successfully deployed. The main advantages of this technology compared to the initial proposal are: Brings effectively two single wells from one slot of the wellhead tower as it provides independent access & control for enhanced reservoir management (well stimulation, production logging and water shut-off). Substantial cost savings due to the utilization of one slot only. Conventional single designs need two slots to deliver equivalent completion requirements. The completion technology meets the Well Integrity Policy & Completion Guidelines stated by ADNOC to have full accessibility to all drains. This is the first Level 5 configuration installed in UAE integrated with a lower completion. The design enhances the benefits of the multilateral construction by providing full mechanical & pressure isolation at the junction throughout the life of the well. Furthermore, accessibility to both laterals from surface without the use of a re-entry deflector or any constraints was deemed to be paramount for a successful well construction.
The objective of this paper is to present an integrated approach to quantify subsurface uncertainties and to share the assessments that have been applied in the subsurface studies of a new offshore oil field development in United Arab Emirates. A methodology was developed to review and rank the various subsurface uncertainties. Seismic and geological tools were used to assess uncertainties of static parameters, while integration of all uncertainties was made in the dynamic simulation model. New approaches were implemented to address two important parameters: Critical Water Saturation and Permeability. Critical Water Saturation uncertainty was derived by history matching production test data using a Saturation-Versus-Height model coupled with a Fractional Flow equation. For estimating uncertainty on Permeability, correlations with core derived fracture densities were developed. Uncertainty on the Critical Water Saturation was found to have the highest impact on oil recovery. This uncertainty is related to an observation already made for other carbonate reservoirs where perforated intervals are sometimes producing at very low water-cut in spite of high water saturations interpreted from the logs. This uncertainty review allowed updating the Dynamic Model with more robust P50 estimates of its parameters. The updated model was used to define a new base case development well scheme and production profile. The study was important in maturing the development studies further. It was used in particular not only for updating the Dynamic Model, but also for defining future studies, preparing a data acquisition plan, and identifying mitigation actions to reduce the subsurface risks.
The ultimate success of an offshore field startup depends on the strategy and integration within an organization. Even more challenging is managing the dynamic interface of subsurface and surface project delivery through the design, construction, hookup, commissioning, and startup operations. This paper presents the case study of a new field startup in Abu Dhabi from the early concept selection through the critical startup phases. Integrated multi-discipline approach underpinned the successful startup when the field achieved first oil production ahead of schedule on February 2015 and exceeded expectation despite the backdrop of global sharp decline in oil price. This paper highlights the technical and functional preparation put in place by the subsurface and surface teams to ensure full integrated readiness and plan-in-place for production start-up. It also outlines the challenges encountered to achieve operational performance and the major lessons learned from the journey. The results demonstrated in this paper shows that an integrated and cooperative approach is key in dealing with delays, prioritization, execution of processes, projects and operations. The lessons learned from subsurface and surface technical preparation, through surface project engineering and delivery phases are presented. Successful management was critical in handling the drilling rigs and barge logistics, offshore installation and commissioning phases, and simultaneous operations during the production start-up and ramp-up of the field. In addition, while encountering pressures to minimize rig time and execute the extensive data gathering program, good team synergy ensured that the milestones were successfully met even with the additional limitation of skilled technical resources. Finally, illustrated in this paper are best practices applicable for new offshore field startups. This proves that even with the financial-demanding outlook and market-down conditions, the successful startup of a new field is essential and visible.
Including "smartness" in your field does not necessarily add additional expenditures. ADNOC Offshore piloted a new well completion design combining Interval Control Valves (ICVs) in the shallow reservoir and Inflow Control Devices (ICDs) in the deeper reservoir, both deployed in a water injector well for the first time in the company. The objectives were to improve reservoir management, reduce well construction complexity and achieve one of the main business targets of cost optimization. This paper covers the subsurface study, detailed well construction design, completion deployment, well intervention and overall well performance in commingled injection mode. A multi-disciplinary study was conducted based on updated reservoir data available after the first two years of production in a heterogeneous multi reservoir field. This study showed the possibility of replacing the upper horizontal drain by a deviated perforated section. The authors identified the need of completion compartmentalization to overcome challenges such as high reservoir heterogeneity and uneven pressure depletion enforced by non selective acid stimulation. As part of the evaluation, a simulation was performed to evaluate the expected injection performance across the four zones with different combinations of ICVs and ICDs in order to cater for different injection scenarios. As a result of the integrated analysis, a new well completion design was deployed to optimize a Dual Horizontal Water Injector into a Single Smart Completion with 3 Inflow Control Valves (ICVs) covering the upper perforated zones and 14 Inflow Control Devices (ICDs) with sliding sleeves across lower lateral reservoir. Cost savings and reduction of rig time was achieved with this new completion design demonstrating very pro-active participation from all involved teams, ADNOC Offshore and Service Companies. The requirements to complete high and low permeability zones in one single well can be successfully accomplished. Firstly, mitigation of early water breakthrough is achieved by incorporating surface water injection control in high permeable zones and secondly, the injection target for the low permeable reservoir is also delivered. Building on the successful results and captured lesson learnt, this new well completion design provided the capabilities to optimize the water injection plan while reducing costs. Therefore, the project has passed the trial phase and the team proposed its implementation.
After a long history of unsuccessful appraisal wells, a new phase of reservoir appraisal focusing on data gathering for reservoir and fluid characterization led to positive results. Fluid sampling, acid recipe, formation pressure, and horizontal drilling were key factors for the successful appraisal. This reservoir is now a significant upside for the field development plan. During the early phase of field development, careful data gathering plan was designed to characterize the reservoir. The plan included coring, logging, reservoir formation pressure, downhole fluid analysis, fluid sampling, conventional Pressure, Volume, and Temperature (PVT) studies, and asphaltene and flow assurance studies. After collecting downhole oil samples, a compatibility study with acid recipe was performed and many chemical additives were tested to find the optimal one. A horizontal drain was drilled to maximize the reservoir contact. The well was tested with drill stem test (DST). Reservoir formation pressure acquired in 4 pilot holes at locations covering the reservoir confirmed fluid mobility, initial reservoir pressure, and possible oil pool limits. Downhole fluid analysis and sampling allowed the characterization of the reservoir fluid properties. Conventional PVT, asphaltene and flow assurance studies confirmed light oil with good flow potential. However, the compatibility study with existing acid recipe showed a high increase in fluid viscosity. This could prevent the well from flowing after matrix acidization. Naphta, among many tested chemical additives, proved to be the best to resolve the viscosity increase. The horizontal drain was successfully acidized with the new acid recipe and the well flowed oil during DST for the first time, 46 years after the field discovery. The well was tested through separator at different chokes before the main pressure build-up (PBU). The well was shut-in for 78 hours. BU analysis showed that reservoir permeability is in line with previously collected cores. Although earlier appraisals were successful in upper reservoirs, a classic approach to reservoir appraisal of this thin oil reservoir failed. Our approach of carefully planning the data gathering sequence, testing acid and oil compatibility, proved essential to understand the past failures, correct the shortcomings, and carry on a successful appraisal.
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