The decision to gravel pack was made for the following reasons: PRELIMINARY WORKThe crude is a high pour point crude with a 32 0 API gravity. Analysis of the crude showed a low asphaltene content of 0.15% to 0.3% and emulsion tests were run on all the acids prior to use. Later crude analysis using gas chromatography would reveal an asphaltene content of 5% to 7%. The crude viscosity at reservoir conditions is 4 -4.2 centipoise.Core work showed the reservoirs to be predominantly quartz with approximately 5 -6% clays. The clays were analyzed as 85% to 95% kaolinite with occasional smectite, chlorite, illite, or feldspar. interdispersed. Sieve analysis identified a gravel size of either 12-20 or 20-40 mesh gravel based on Saucier's criteria * *

Summary Brine displacements were one of several areas of focus in a continuous process to optimize completion methodology in Amerada Hess's Ceiba project wells, located in deepwater offshore Equatorial Guinea. The time between making up the cleaning string and laying it down, after displacement and filtration operations are completed, can exceed two days and cost U.S.$500,000. It is imperative that wellbore-cleaning operations are performed efficiently and correctly the first time. Amerada Hess and its brine suppliers, working together in a joint task force, have taken specific steps to minimize the time required for displacement and filtration operations. Introduction The Ceiba field in deepwater Equatorial Guinea was discovered in mid-1999 by Triton Energy Ltd., now Amerada Hess. To date, 20 wells have been completed, and three wells have been recompleted. Ongoing development of the field still continues at this time. Five of the wells were completed as openhole gravel-packed producers. The others were cased-hole producers or injectors. The initial average pore pressure in the field was 8.7lbm/gal, and the majority of wells in the field were completed in a 9.0 to9.2-lbm/gal CaCl2 brine. This fluid was selected because of its minimal damage effect during core tests and its ready availability at stock points in the west Africa operating area. All wells were drilled through the pay interval by use of mineral-oil-based mud. The Ceiba field lies in approximately 800 m of water. The wells flow through individual subsea flowlines for 8 to 11 km to a floating-production, storage, and offloading unit that was positioned to receive first oil in the late fall of 2000.1 The semisubmersible Sedco 700 has been on location in the field since the spring of 2000 and has drilled the majority, and completed all, of the Ceiba development wells. As part of a continuing improvement program used throughout the development of Ceiba, a critical review of brine-displacement practices was performed to optimize this process. A review of cased-hole completions by the taskforce indicated room for improvement in our displacement process and chemical usage. At the time the task force was formed, the average displacement took 25or more hours, with up to 4,000 bbl of completion brine discarded because of poor quality and filtration problems. This paper examines the stages of mud-to-brine displacement used in the cased-hole completions of the Ceiba deepwater development and demonstrates how these stages were adjusted in their relationship to one another to make a more efficient displacement. Data are presented to show simplification of procedures, improved mud-solids removal, shorter filtration time, reduced loss of brine, and shorter rig timeover the course of the development. These modifications and changes had a major impact on time and cleaning efficiency. Please note, Ceiba openhole-completion displacements are not addressed in this paper.

Proposal The paper details a study of 15 fifteen frac-packs in twelve wells in the Ceiba Field, offshore Equatorial Guinea.Initial frac-packs were very unpredictable, experiencing numerous early wellbore screenouts and unpredictable tip screenout (TSO) behavior, placing proppant volumes of 10 to 160 klb with TSO net pressure increases ranging from 100 to 1,500 psi. The goals of this study were to:develop a fracture modeling approach that would more reliably predict TSO behavior using mini-frac data,develop reliable mini-frac analysis procedures anddetermine the primary cause(s) of the early wellbore screenouts. The study resulted in improved designs, better execution procedures, more predictable TSO behavior and a reduction in early screenouts. After reliable analysis procedures were developed, it was clear that mini-frac fluid efficiency and net pressure varied dramatically in the Ceiba frac-packs, with efficiencies ranging from less than 5% to over 30% and net pressure ranging from 170 to 900 psi. After reviewing rock mechanical data and evaluating various fracture modeling approaches, the variations in net pressure were attributed to complex fracture growth due to high wellbore deviation and long perforated intervals (as opposed to differences in modulus). The combination of consistent mini-frac analysis procedures and a fracture modeling approach that included fracture complexity resulted in a much more reliable prediction of TSO behavior. Introduction The Ceiba Field is located offshore Equatorial Guinea (Figure 1). The oil productive interval is characterized by a 100- to 650-ft section of laminated sand-siltstone-shale sequences (8,200 ft TVD). Well deviation through the pay ranges form from near vertical to 60 degrees. There are several high permeability but poorly consolidated sands targeted for frac-pack completion, with permeability ranging from 100 to 1,000 mD.[1] Overview and Objectives of Frac-Pack Evaluation. A comprehensive evaluation of Ceiba frac-pack treatments was performed to improve completion performance. The objectives of the evaluation were to:Develop a calibrated fracture model that would accurately match actual treatment behavior and reliably predict TSO behavior using mini-frac data.Develop an Excel database that contained fracture treatment information, mini-frac results, completion details, reservoir properties, fracture modeling results and treatment analyses that could be used to improve future designs and real-time job design changes by providing easy access to previous mini-frac analyses and treatment schedules, while also providing a platform for treatment evaluations.Develop consistent and reliable mini-frac analysis procedures.Identify the primary factors that cause premature wellbore screenout to allow future designs and/or completions to be altered to improve treatment success and reducing premature screenouts.

In contrast to the common use of a hydraulic fracturing treatment in low permeability formations, recent advances of these treatment have overcome the limitations of matrix acidizing treatments performed in high permeability formations common to Indonesia. Being gravel packed with 5 Darcy permeability formation, WIA-8 well showed lower than expected productivity after completion. Efforts to restore the well productivity using matrix acidizing treatments resulted in additional productivity impairment. Recently, the well was worked over and the formation was treated with a small volume, high concentration, propped fracture treatment which successfully rectified the impairment. This is believed to be the highest permeability formation ever hydraulically fractured. This paper will outline the methodology used to design and perform a hydraulic fracturing treatment in high permeability formations. INTRODUCTION Widuri field is 90 miles (145 kms) north of Jakarta in the Java sea. The field is located on the northwest flank of the newly developed Asri basin (Figure 1). The field was discovered in April 1988 vkaen Widuri-1 well was drilled to a total depth of 3735' subsea and encountered 170' of net oil pay in the Talang Akar sandstone formation. The field structure is a faulted anticline formed in the early Miocene age shortly after deposition of the sandstone formation. The trapping mechanism is both structure and stratigraphy with hydrocarbon deposits found in six immature fluvial or distributary channel sandstone formations from 3200' to 3700' subsea depth1. Most Widuri wells are gravel packed initially in an individual sand formation and produced using electrical submersible pumps. The subject of this paper, WIA-8 well, is gravel packed in the 35-1 formation which is unconsolidated sand with a log porosity of 29% and a test permeability of 5 Darcies. After completion, some Widuri wells had experienced a productivity impairment. In August 1990, laboratory analysis was commenced to investigate the cause of the impairment and to determine an appropriate treatment. The results lead to performing subsequent matrix treatments on the WIA-8 well (Figure 2). In February 1992, a hot solvent treatment pumped into the well resulted in an additional productivity impairment. In April 1992, a retarded mud acid treatment performed in the well caused a severe productivity impairment. In November 1992, a revised retarded mud acid treatment with an improved clay stabilizer pumped into the well did not improve the productivity impairment.

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