The Usan deepwater field, located approximately 100km south of Port Harcourt, has multiple oil bearing turbidite sand bodies of varying thickness and permeabilities separated by thin and massive shale intervals making difficult the selection of completion intervals. Fracture height confinement is challenging due to the small stress contrast between the sand bodies and the bounding shales, and variability of stress field in a very compartmentalized environment. Frac pack completions in this deepwater field were designed and executed to fulfill four main drivers:• Ensure sand control completion integrity and long term reliability • Deliver wells with low skin and good wellbore-fracture connectivity along entire completion interval • Maximize reserves by increasing number of sand bodies connected by frac packs • Reduce capital expenditure and installation risk by minimizing number of frac pack jobs This paper illustrates the systematic approach used to optimize the frac pack completions in the Usan field by improving each of the following areas:• Completion brine formulation to minimize emulsion and clay instability problems • Perforation interval to maximize reservoir exposure without compromising frac pack quality • Frac pack fluid testing to ensure low formation damage and stability at wellbore conditions • Frac pack model calibration to improve fracture height coverage and confinement, and net pressure built after tip screen-out (TSO) • Frac pack sensitivity analysis using two simulators accounting for uncertainty of input data and numerical modeling • Post job analysis integrating surface and downhole data • Well flow backs to evaluate initial completion integrity and performance Actual field data from several wells are used to illustrate the evolution of the frac pack completions in the Usan project. The main challenges, lessons learned and improvement opportunities captured during the first two years of the Usan completions campaign are also discussed in detail.

Reservoir compaction in deep water, unconsolidated, turbidite reservoirs can cause large-scale permeability damage to near-wellbore area, the resulting skin reducing the well productivity. This is due to the depleting reservoir pressure resulting on an increased effective stress on the fabric of the reservoir rock leading to a reduction in both permeability and porosity. Permeability reduction will decrease recovery while porosity reduction will improve recovery by maintaining the fluid pressure & increasing the oil saturation. The interplay of these phenomena was studied using a reservoir simulation model of a typical deepwater, compacting, compartmentalized layered reservoir. Eighteen months production experience was available for history matching. This paper will show how the above understanding can be used to optimize the well performance and explain "unusual" production performance observations e.g. a decreased water cut was predicted if water injection was implemented. This study reviews the potential value creation through development of a compacting reservoirs using Intelligent Well Technology (IWT) compared to a conventional well development. IWT offers great flexibility to monitor, operate and control production at the Zone and Reservoir level. This led us to examine whether the draw down around the wellbore could be optimized so that permeability damage is minimized as a means of increasing recovery in compacting reservoirs. This paper shows how evaluation of I-well value generation has to combine the traditional reservoir engineering studies of well location and pressure maintenance while simultaneously optimizing the details of the well completion design and the newer technologies associated with managing compacting reservoirs. A doubling of the field reserves was predicted by completing the new well with IWT. IWT also effectively managed non-optimum situations e.g. placement of the well in the incorrect location. Introduction The CT Field is located approximately 170 miles south-southwest of New Orleans some 2,100 feet of water (Figure 1). One of the major concerns facing the CT development team that the production was planned from two, separate, unconsolidated sands. IWT is thought to be the tool that can help to solve some of the resulting challenges. The high cost of I-well developments makes it essential that the reservoir behavior is sufficiently well understood that a confident value-proposition can be made before making the decision to install such technology in the field. The potential benefits from IWT for a two reservoir sand system has frequently been discussed[1–5]. In these field applications improved production performance was achieved from commingled completion zones (or reservoirs) with very different properties or when different fluids are being produced. The new factor introduced in this study is the high level of reservoir rock deformation occurring due to formation pressure depletion during oil production.

It is important to understand the effects of introducing thermal changes in the subsurface because such changes alter the state of stress and, ultimately, the behavior of the formation. Inducing fractures in the formation may cause injection fluids to advance at different rates through the reservoir, thereby reducing the areal sweep through the reservoir and the overall efficiency of a flooding operation. To avoid induced fractures, it is necessary to maintain water flooding operations below the fracturing (breakdown) pressure of the formation. For these reasons, it is extremely important to model the cold water injection response and to predict whether it is possible to inject without creating fractures in the formation. In late 2006 a reservoir simulation study using ECLIPSE was performed for 103N Field in Sirte Basin to evaluate the reservoir response to water flooding in an attempt to understand the potential for improving oil and gas recovery with water flooding. This study showed that the main effect of cold water injection on the recovery of N- Field was reduced injectivity due to high water viscosity. Another effect of cold water injection was that bypassed oil was cooled down and its mobility was reduced due to the increase in the oil viscosity, thus reducing ultimate recovery. This paper provides an extension of the reservoir simulation done by Wintershall to examine the effect of cold water injection on formation fracturing gradients. The work includes a review of the rock mechanics and stress analysis of the subsurface formations and provides an estimation of fracture penetration within the reservoir for a range of water injection rates and water surface temperatures. The conclusions of this study provide important insights into applying water flooding operations in the N-field. Introduction Undisturbed subsurface temperatures typically increase from surface to bottom hole. In oil and gas wells, reservoir temperatures of 150 °F to 350 °F are common. These reservoir temperatures remain relatively constant during the primary production phase of a oil or gas reservoir, that is, most primary production occurs under isothermal conditions. All points in the subsurface are subject to a state of stress in addition to temperature. This state of stress occurs as a result of the depositional environment and subsequent tectonic forces applied to the formation. The stresses, both from rock matrix and pore fluids, are resolved for any point in the formation and represented as a system subjected to three principle stresses. When fluids are injected into a well, such as during water flooding or tertiary recovery processes, the temperature of the fluids injected is typically cooler then the in-situ reservoir temperature. Continuous injection of this colder water creates a thermal gradient around the wellbore, with the coldest temperature at the wellbore and the warmest temperature at a point ahead of the injection front. The heat transfer (cooling) which occurs is a function of the formation porosity and permeability, the injection rate, and the initial thermal differential.

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