Search

Objective/Scope Abu Dhabi National Oil Company (ADNOC) places a priority on People Development. The reorganisation in 2016, a changing demographic, and increased emphasis on "Emiratisation" of the workforce has only reinforced that priority. The reorganisation fused together disparate companies, each with its own competency standards. The goal of ensuring that UAE national staff are used and developed throughout the organisation, coupled with our demographics, has added to the requirement for standard set of measures and processes for capability development across the ADNOC Group. This initiative has been implemented in phases, beginning with the creation/unification of core technical, behavioral/leadership and business competencies for all subsurface disciplines across the Group. We are now creating a learning organization to address our remaining challenges. A joint effort is required between our human capital and technical discipline leaders. Methods, Procedures, Process The ADNOC Competency Frameworks were created through a joint effort between subject matter experts (SME) and the People Development Team. The deployment of these frameworks was done in two main steps:Creation and verification. This was a joint effort between our Human Capital organisation and domain experts from the operating companies. This deployment also saw the creation of discipline authorities for the subsurface organisation. These "Heads of Discipline" are domain experts with a focus on skills and staff development. A "self-assessment" + "manager verification" process was used to populate the competency framework database.Data analysis. A statistical subset of the data were independently verified by SME interviews. Anomalies, and disciplines with insufficient coverage were scrubbed from the data. A number of analytical tools were used for data analysis, including "Heat Maps" for visual impact.Results, Observations and ConclusionsThe results revealed strength in the "engine room" of the organization, however, some "gaps" were identified. One gap was identified in the transitional grades between the "junior" and "operational" staff. This was consistent for all disciplines, and it is being addressed through specialized training and on-the job work assignments. Another gap was identified in some specialties, in which ADNOC depends on one or two individuals for key skillsets.As we took immediate action to address some gaps, we recognised that a longer term solution was required. This has taken the form of the ADNOC Learning Institute (ALI). The ALI is a comprehensive solution which includes strategic workforce planning, future capabilities, competency and learning frameworks. These will underpin future efforts in technical succession planning and mobility.Novel AdditionsThe ADNOC Learning Institute was crafted to meet the competing challenges of skills development, demographics and Emiratisation. The ALI demonstrates how a unified vision is required to meet future challenges.

The capacity for the storage of carbon dioxide in saline aquifers remains enormous. Of all geological storage media, it provides the best storage capacity. In this study, the potential of the Shuaiba Formation, in the Falaha syncline, for geologic sequestration is assessed. A regional geo-model was built using seismic and well data (logs, cores) from the Falaha Syncline and nearby fields. The model was built to honor the heterogeneity and sequence stratigraphy of the Shuaiba carbonate platform using a five-order hierarchical conceptual model of the Shuaiba formation that merged sequence architecture and reservoir architecture together. This was achieved by honoring lithofacies, facies association packages and rock types in their corresponding depositional settings in the sequence framework. Dynamic simulations were then conducted on an upscaled geological model using a compositional reservoir simulator to determine its storage and flow capacity, plume migration pathways and to understand the physics of the fluid flow in the aquifer. Simulations are made to be conservative thus accounting for structural/stratigraphic, solubility (dissolution in resident brine) and residual trapping without accounting for the slower mineral trapping process. Detailed sensitivity studies were conducted during the simulations to understand the effect of well parameters, rock and fluid properties amongst others on the storage capacity in the aquifer. Simulation results indicate that significant volumes could be stored in the aquifer and could take a significant amount of time before the injected gas reaches the surrounding hydrocarbon producing fields. This study provides the first full field approach to characterize and to quantify the suitability of the identified aquifer for long term storage of carbon dioxide in the subsurface of UAE.

Microporosity quantification is becoming increasingly important to assess the distribution of hydrocarbons and their remaining/residual saturations after water flood (and /or gas flood). Assessing uncertainties and limitations in microporosity estimations of carbonate cores, comprising different reservoir rock types have been a challenge for geoscientists. The advent of Digital Rock Physics (DRP) based measurements allow the pore 3D network images from Micro and Nano - Computed Tomography (CT) scans on selected sub-samples to map representative cores and Reservoir Rock Types (RRT). The DRP based microporosity is rigorously examined and compared with other techniques/tests. Conventional techniques, such as Mercury Injection Capillary Pressure (MICP), Nuclear Magnetic Resonance (NMR), Thin Section (TS) and Backscattered Scanning Electron Microscopy (BSEM) are used for semi-quantitative evaluations of microporosity. Images at different magnitudes (4X, 10X, 40X and 100X) were captured from TS and BSEM, and used to quantify porosity using image analysis software. NMR and MICP measurements acquired through a commercial laboratory were also analyzed to quantify the microporosity. DRP based 3D pore network images have been acquired at different scales of interrogation from Nano to micron meters to define microporosity. Preliminary measurements on carbonate cores from a giant onshore field of Abu Dhabi, reveals an inverse relationship between microporosity and permeability.Microporosity impacts the porosity-permeability correlation. The relationship between porosity and permeability of carbonate reservoirs shows a better correlation when microporosity is deducted from the total porosity of the reservoir. A detailed analysis is presented along with Best Practices in estimating microporosity of carbonates.

This paper discusses the planning process, execution and lessons learned of an advanced horizontal water injector in a tight carbonate reservoir, onshore United Arab Emirates. The well design required a 10,000 ft horizontal section, to be geosteered in a 6⅛-in. hole through a narrow TVD window of 5 ft, just above the oil water contact. The challenges were multiple, not only from the rig capability and BHA design point of view, but also from the geosteering and formation evaluation aspects pertaining to borehole hydraulics, completion and stimulation. For injection monitoring analysis the completion had to be run with a perforated 3 1/2-in. stinger design to deploy a 19,500 ft distributed temperature sensing (DTS) system to TD. Four main justifications to execute this pilot project were identified: to improve injectivity and therefore the area sweep efficiency in the down flank area of the field to segment the wellbore to provide for future selective stimulation along 10,000 ft of horizontal section to deploy a DTS system to continuously monitor the water injection profile to minimize the number of injection wells in the field, reducing CAPEX, OPEX, surface hook ups and field footprint. The paper discusses the business case for this project, which includes an initial pilot well containing a 5,100 ft lateral section and four extended reach drilling (ERD) wells, each with a 10,000 ft lateral hole section. Furthermore, best practices from the detailed planning phase to the execution of the first extended reach well are reviewed in this paper.

This paper represents a case history of a full-field development plan for one of the major fields (field "A") in Abu Dhabi Company for Onshore Oil Operations (ADCO-UAE) consisting of three different reservoirs. Field (A) development is becoming increasingly complex and expensive as this field acts as a hub for another two producing fields and several undeveloped fields. This involves developing an efficient design and planning philosophy. Best practices in integrating new technologies in materials, construction, operations as well as management techniques including the right team to really be successful are all part of the "big picture". ADCO assigned a cohesive and highly motivated team involved in the ‘big picture" event with a clear direction in terms of policy, risks and implementation aimed to shorten the decision process without compromising the company Major Project Approval Process (MPAP) requirements and Shareholders guidelines. The Project Management main factors that were tackled successfully during this event were the focus on profitability and increase of NPV by adopting a multi-disciplinary approach to field management; align various departments involved right from the concept to the implementation stage through continuous interaction; cultivate an open-ended approach to all aspects of engineering and Field Management by taking into account both the surface and subsurface perspectives of oilfield Project Management. The paper will also address the structure of the team and how it set feasible targets in terms of production building blocks of other fields through eventual expectations in terms of surface facilities and helped in overcoming challenges and minimizing risks through careful integrated risk register. Finally assessed specific problems and issues relevant to the field operability and evaluate possible strategies to tackle it. The key objective and achievements of the event were the deliverables for the Stage-4 of the MPAP. The paper will discuss the achievements as a result of this event. The integration of the development options alternatives, into a single development plan enabled shortening the decision process and secured Shareholders approval on Gate-5 finance proposal as it was recognized as an economically favorable development opportunity. The development plan continued to other Gates (7 & 9) with the same approach in order to properly accomplish the success of such plan with a value of multi Billion USD.

Reservoir rock typing is a process by which geological facies are characterized by their dynamic behavior. The dynamic behavior of the facies is assessed by studying the rock texture, the diagenetic processes which overprinted the initial fabric, and the interaction between the rock itself and the fluids. Porosity, permeability and pore size distributions characterize the rock texture while capillary pressure, relative permeability and wettability describe the rock-fluid interaction. Reservoir rock typing is a synergetic process between geology and petrophysics/SCAL. It is therefore a process by which various petrophysical parameters and dynamic measurements obtained from SCAL are integrated in a consistent manner with geological facies (lithofacies) to estimate their flow (dynamic) behavior. The relationships between lithofacies and reservoir rock types (RRTs) is complex because of the inter-play between facies, diagenetic processes and the rock-fluid interaction (wettability changes) in the reservoir. Similar lithofacies, deposited under the same depositional environments, may exhibit different petrophysical properties due to diagenesis. Therefore, lithofacies deposited under similar geological conditions may experience different diagenetic processes resulting in different petrophysical groups with distinct porosity-permeability relationship, capillary pressure profile and water saturation (Sw) for a given height above the Free Water Level (FWL). On the contrary, lithofacies deposited in different depositional environments, might exhibit similar petrophysical properties and dynamic behavior. The authors emphasize on the need to have a good understanding of the original facies, depositional environments, subsequent diagenetic processes and rock-fluid interaction (via SCAL) to be able to unravel the relationships between lithofacies, petrophysical groups and rock types. A workflow for carbonate rock typing addressing some of the industry pitfalls and the differences between lithofacies, petrophysical groups and rock types are presented in this paper.

This paper presents the methodologies and approaches adopted by the Asset Team to integrate geomechanics at the early stages of a field development. The reservoir is a tight carbonate formation, with low structural relief and is offset by major strike-slip faults. The development plan called for a line drive pattern of horizontal producers and injectors (4000 ft open-hole completions), targeting layers with different petrophysical and geomechanical properties. Water-Alternating-Gas (WAG) was selected as the main recovery process. The main concerns at the early stage of field development were the following: 1) What is the best orientation for the horizontal wells ?; 2) Will there be any thermally induced fracturing during injection ?; 3) What would be the role of the existing faults within the development area ?; Would any fault reactivation be expected ?; 4) What would be the impact of joints/faults as permeability enhancements due to pressure and/or temperature gradients. 5) Is there any stress dependency of porosity and permeability ? All these questions were addressed before planning the horizontal wells by conducting a judicious and fit-for-purpose geomechanical study. The aim of this paper is to summarize the geomechanical workflows conducted in the Team prior to the drilling campaign to assess the best orientation for the horizontal wells.