This paper describes a methodology for incorporating uncertainties in theoptimization of well count for the deepwater Agbami Field development. The lackof substantial reservoir description data is common in many deepwaterdiscoveries. Therefore, the development plan must be optimized and proven to berobust for a wide range of uncertainties. In the Agbami project, the design ofexperiments or experimental design (ED) technique was incorporated to optimizethe well count across a wide range of subsurface uncertainties. The lack of substantial reservoir description data is common for manydeepwater discoveries. In the Agbami project, the uncertainty in oil in placewas significant (greater than a factor of two). This uncertainty was capturedin a range of earth (geologic) models. Additional uncertainty variables, including permeability, fault seals, and injection conformance, were studiedconcurrently. Multiple well count development plans (high, mid, and low) weredeveloped and used as a variable in ED. The ED technique allowed multiple wellcounts to be quickly tested against multiple geologic models. With the netpresent value (NPV) calculated for each case, not only was the well count forthe overall highest NPV determined, but discrete testing of each geologic modeldetermined the optimum well count for each model. The process allowed testingthe robustness of any well count versus any uncertainty (or set ofuncertainties). A method was demonstrated quantifying the difference between perfect andimperfect knowledge of the reservoir description (geologic model) as itpertains to well locations. Introduction The Agbami structure is a northwest/southeast trending four-way closureanticline, and is located on the Niger delta front approximately 65 milesoff-shore Nigeria in the Gulf of Guinea (see map in Fig. 1). Thestructure spans an area of 45,000 acres at spill point and is located in 4800ft of water. The Agbami No. 1 discovery well was drilled in late 1998. Theappraisal program was completed in 2001 and included five wells and onesidetrack drilled on the structure with each encountering oil pay. These fivewells and a sidetrack penetrated an average of approximately 350 ft of oil. In this phase (Phase 3) of the development process, the key objectives areto construct a field development plan and to obtain sanctioning. With drillingdepths of up to 10,000 ft below mudline in 4800 ft of water, well costs atAgbami will be at the high end of typical deepwater costs. Therefore, animportant optimization parameter in the field development is the total wellcount. Agbami is typical of many deepwater developments in that the seismic is lessthan perfect and the appraisal well data are sparse relative to the areacoverage. Therefore, subsurface uncertainty is high. In fact, the 5% probableoil in place is more than two times the oil in place at the 95% probability. Asa result, the development process is challenged with determining the optimumwell count for the field development across the wide range of subsurfaceuncertainty. Several key development decisions were determined in the previous phase(Phase 2) of the development process. These decisions were taken as givens inthis study and are listed as follows:Recommended pressure maintenance scheme and gas disposition strategy for the17 million-year (MY) units is a combination of crestal gas injection withperipheral water injection.Recommended pressure maintenance scheme and gas disposition strategy for the14MY/16MY units are crestal gas injection only.Facility design capacity recommendations are:250,000 stock-tank bbl per day (STB/D) oil450,000 thousand cubic ft per day (Mcf/D) gas production250,000 STB/D water production450,000 STB/D liquid production450,000 STB/D water injection

The Agbami project team was challenged to generate a field development plan and to assess that plan over a wide range of uncertainty. Complete stakeholder alignment around the technical aspects of the development plan was a critical issue. Field data, laboratory data, and analog data were incorporated into a range of reservoir simulation models. The field data included appraisal well logs, cores, 3D seismic, fluid samples, pressure data, and drill stem tests. Three hundred reservoir models were constructed and ranked using streamline simulation for both static and dynamic attributes to assess the range of subsurface uncertainty. A project team with significant but diverse deepwater development experience was formed and co-located. A formal phased decision making process was implemented. During each phase of the process key parameters of uncertainty were identified and ranked in terms of project impact. Field development options were evaluated in distinct phases over the full range of uncertainty. Experimental Design (ED) methodology was used throughout the evaluation to obtain the maximum information with the minimum computational effort. The paper shows how the results from this process facilitated the identification of the key uncertainties and provided direct input into economic models for decision analysis. In Phase Two of the evaluation the pressure maintenance scheme selected for the 17 million year (MY) reservoir was crestal gas re-injection with peripheral water injection. Crestal gas re-injection was selected for the 14MY and 16MY reservoirs. The facility capacity requirements were also selected during this phase at 250,000 stock tank bbl of oil per day (STB/D) and 450,000 thousand standard cubic ft per day (Mscf/D). Peer reviews and assists were held and alignment was obtained along with action items to be included in the subsequent phase. In Phase Three of the evaluation the well count parameter was investigated and an optimum number of 38 wells was selected. Production profiles were generated and presented in terms of P10, P50, and P90. Introduction This paper will focus on the application of Experimental Design (ED) during Phase Three at Agbami. With drilling depths of up to 10,000 ft below mudline in 4,800 ft of water, well costs at Agbami are at the high end of typical deepwater costs. Therefore, the number of wells including their type and location is an important optimization parameter in the field development plan. The probabilistic forecast of all produced and injected fluids is also a key deliverable of the field development plan. Agbami project stakeholders are aligned on all technical aspects of the field development plan and the project is rapidly proceeding toward sanction and awarding of major contracts.

This paper describes the methodology for incorporating uncertainties in the optimization of well count for the deepwater Agbami project. The lack of substantial reservoir description data is common in many deepwater discoveries. Therefore, the development plan must be optimized for a wide range of uncertainties. In the Agbami project, the design of experiments or experimental design (ED) technique was incorporated to optimize the well count across a wide range of subsurface uncertainties.Multiple well count development plans (high, mid, and low) were developed and used as a variable in ED. Also, multiple geologic models representing the broad range in uncertainty in oil in place (greater than a factor of two) and in net-to-gross were built and used as a variable. Additional uncertainty variables, including permeability, fault seals, and injection conformance, were studied concurrently. The ED technique allowed multiple well counts to be quickly tested against multiple geologic models. With the net present value (NPV) calculated for each case, not only was the well count for the overall highest NPV determined, but ED allowed discrete testing of each geologic model to determine the optimum well count for each model.A methodology was developed for optimizing well count development plans over a broad range of uncertainties including a range of geologic models, which vary in oil in place and net-to-gross. The process allowed testing the robustness of any well count versus any uncertainty (or set of uncertainties).A method was demonstrated quantifying the difference between perfect and imperfect knowledge of the reservoir description (geologic model) as it pertains to well locations.A total well count of 38 was concluded to be the optimum well count for the Agbami project based on NPV. This well count proved to be robust across the full range of uncertainties tested.

Planning the development of the Agbami field offshore Nigeria, as with other deepwater projects, required that critical business decisions be made in the absence of extensive subsurface data. Along with other fundamental project components that have a range of possible outcomes-for example, finalized commercial terms, wells and facilities costs, and execution schedule duration-the project team had to effectively understand, communicate, and incorporate all the key subsurface uncertainties in the process of achieving certain field development decisions.ChevronTexaco uses its gated five-phase ChevronTexaco Project Development and Execution Process (CPDEP) to mature and execute all major projects. In "CPDEP-speak," Phase Two involves the generation and selection of alternatives. Phase Three is where a "Preferred Alternative" is refined in preparation for project execution in Phase Four. Additional explanation of CPDEP follows in a separate section.Prior to moving the project into Phase Three, two critical field development options required resolution: 1) facility processing and injection capacities (oil, gas, water); and 2) a dry tree unit (DTU) versus all-subsea development decision. It was required that these development plan options be evaluated over the range of possible subsurface and cost regime outcomes in order to select the optimum development scheme.Probabilistic estimates for reserves, well count, facility costs, well costs, and schedule were developed. Uncertainties such as a potential reserve differences between dry and wet tree development and management of multiple contracts were included in the options analysis. Other operators' decisions for similar deepwater developments were benchmarked for best practices and lessons learned.Various project variables were ranked in terms of project impact in order to determine which ones drove each decision and therefore which ones needed to be most fully evaluated in terms of understanding the range of possible outcomes.

With up to several billion barrels of oil in place, the Agbami project represents a true world-class development. Multiple stacked pay zones, 4,800 ft of water depth, and adherence to the no-flare environmental policy were some of the hurdles that required the best of deepwater experience and state-ofthe- art technology. To overcome hurdles in the development plan such as the selection of pressure maintenance scheme, facility capacities, and gas disposition, a rigorous technical team effort and a well informed decision board was required. Thorough descriptions of the field logistics, acquired data, and technology gaps posed some of the challenges presented by the Agbami project. Necessary decisions were made to staff the technical team correctly and to lay out the road map that led to an optimized development plan. This paper provides an asset overview of the Agbami field development project, with a focus on the following topics:The Agbami development and the available dataThe selected pressure maintenance schemeThe facility conceptThe project stakeholdersThe technical team with diverse experiences, disciplines, and backgroundsThe formal phased decision-making process Introduction This paper will provide an overview of the Agbami project with a focus on the preparation of the field development plan. Agbami project stakeholders are aligned on all technical aspects of the field development plan and the project is rapidly proceeding toward sanction and awarding of major contracts. Key success factors to date have been:World class asset with critical mass for stand alone developmentImplementation of a formal phased decision making processA diverse work team with significant deepwater experience from the North Sea, Campos Basin, Gulf of Mexico, and the Nigerian Shelf that was co-located for technical workExtensive use of peer assists and peer reviewsApplication of state-of-the-art technology including experimental design (ED)1–4 World Class Asset. The Agbami structure is a northwest/ southeast trending four way closure anticline and is located on the Niger Delta front approximately 65 miles offshore Nigeria in the Gulf of Guinea (see map in Fig. 1). The structure spans an area of 45,000 acres at spill point and is located in 4,800 ft of water. The Agbami No. 1 discovery well drilled in late 1998. The appraisal program was completed in 2001 and included five wells and one sidetrack drilled on the structure with each encountering oil pay. These five wells and one sidetrack penetrated an average of approximately 350 ft of oil. With up to several billion barrels of oil in place, this discovery represents a true world-class development. Although the seismic quality is less than ideal, the data indicates that a high degree of complexity is prevalent at Agbami. The structural and stratigraphic complexity needs to be discussed briefly to set the background for the earth (geologic) modeling. A complex stratigraphic architecture has been detected from seismic, with three or more distinct pressure isolated reservoirs (see Fig. 2) confirmed by modular dynamic test data (MDT). The reservoir model captured three of these as the 14 million year (MY), 16MY, and 17MY reservoirs.