Many West Africa Offshore Fields are maturing and operators are completing secondary targets in their wells to maintain the economic operation of their valuable assets. However, off-shore environment makes the capital expenditure associated to this kind of interventions of critical importance. It follows that the selection of the right and most remunerative activities is crucial. In the Kitina Field, offshore Congo, deeper sands have been produced to economic depletion and reservoir studies allowed the determination of alternative production intervals for production maintenance. Large quantities of reserves can be found in low permeability, consolidated, formations as well as in very deep and remote culminations. During the first semester of 2007, the Kitina field production increased of 160% reaching a production level lost since early 2004. This was achieved with a variegate set of actions on different reservoirs:infilling the Kitina South culmination with the long reach and ultra deep well KTM-SM5,a massive multistage hydraulic fracturing campaign carried out on the three wells draining the low permeability 3A reservoir and 3rd) with the sweep optimization of the reservoir 1A. Eight propped hydraulic fractures were placed in three re-completed, cased-hole wells with very significant production improvements. These represented the first applications in Congo of different technologies opening a wide range of further applications in similar environments. The paper describes the 2007 and 2008 Kitina rejuvenation campaign with an eye to all the disciplines involved, from reservoir engineering and modeling, to operation geology, drilling and completion, production. The papers focuses with more detail on the successful multi-stage hydraulic fracture campaign from the preliminary design and production forecast pre-job to the reservoir model history match and forecast phase post-job. Interesting reservoir engineering overviews of the future development of the field via improved and enhanced oil recovery techniques are also presented. Introduction Existing oil and gas fields are maturing and new finds are more complex to discover and produce. In today's oilfields portfolio, mature reservoirs production maintenance and increase represent the biggest challenge to face over the next decades to meet the continuously increasing demand for hydrocarbons. Technology research, development and innovation have been the recent answer to sustain the world's oil and gas production and will continue to be so. However, new developments in technology need professionals who are taking the risk of testing them keeping in mind that the failure can be sometimes only a temporary and/or necessary stop towards the success. Mature fields can represent the "working ground" and "technological gyms" where to test new techniques with the final aim of accelerating and increasing reserves. Mature fields have to be seen today as opportunities for improvement rather than declining assets. Accurate candidate selection, optimized treatment design, sound reservoir modeling of production forecast represent crucial and interdependent factors for successful economic evaluations.

This paper presents the methodology applied to optimise the dynamic simulation of the giant Bu Attifel oil field (Libya) producing for 21 years under water injection. When building the full field model of a giant field it is fundamental to limit the number of cells and CPU times without jeopardising the structural and sedimentological complexity of the reservoir. This will allow a correct simulation of future development phases, such as improvement in water injection (production-injection scheme optimisation, infill wells) and EOR processes (gas injection). The first step of the study was the construction of two-dimensional cross sections based on the geological and dynamical data of the most representative wells. Then different oil displacement processes (water injection and gas injection) were simulated, mainly varying vertical communication and anisotropy of layers. Groups of relative permeability pseudo functions, consistent with the different geological configurations, were used in the full field model to simplify and optimise the history match phase. Introduction The complete reservoir study was aimed at optimising the future phases of the exploitation of Bu Attifel oil field by using a 3-D simulation model. The numerical model had two ambitious targets:–to respect the main physical properties shown by the field production performance,–to simulate the behaviour of each single well as accurately as possible to obtain a reliable tool also for short term reservoir management. This would require too large a number of computational grid blocks with very long CPU times. The use of pseudo functions of relative permeability is a means of decreasing grid dimensions without compromising simulation accuracy. These functions scale up the results of laboratory core flooding experiments to macroscopic sand sections (full field model layering). Therefore, they take into account the effect of reservoir heterogeneity and gravity forces. P. 413

Brownfield field have been defined as mature field in a state of declining production or reaching the end of their productive lives. Nevertheless these fields provide more than 50% of world's production as well as world's reserves and so it will be for next 20 years. For that reason revitalization of mature fields has to be a "must". The Kitina Field, offshore from Pointe Noire, Congo, is one such field. Deeper sands have been produced to economic depletion and, in order to maintain the economic operation of their valuable assets, alternative production intervals have been opened to production. Most of these low permeability reservoirs can produce at economic rates only with the application of hydraulic fracturing treatments in a multi-fractured well scenario. Accurate candidate selection, optimized treatment design, sound reservoir modeling of production forecast represent crucial and interdependent factors for successful economic evaluations. This paper describes the massive hydraulic fracturing campaign carried out between April and June 2007 on the Kitina 3A reservoir, offshore Congo. Eight hydraulic propped fractures were placed in three re-completed, cased-hole highly deviated wells with very encouraging production increases (stabilized production increase ranging from 2 to 3 times). The transverse multi-fracturing technique was adopted. This technique utilizes a series of packers and frac-ports that are sequentially shifted allowing continuous placement of more than one hydraulic propped fracture without shutting down the pumping equipment. All the aspects from candidate selection, pre-job design, on-site operations and post job evaluations with particular focus on the operational challenges encountered are described. Recommendations for the future applications of this stimulation technique are proposed. Furthermore, the challenging theme of forecasting mid-long term production profiles for horizontal, slanted and vertical multi-fractured wells is tackled. Different analytical and numerical models, approaching the task with various methodologies, were applied and tested to define the production profiles of the three candidate wells, which differ in terms of geometry and reservoir properties. On the base of the experience gathered on such wells, some general guidelines were drawn for a wider application. Introduction The Kitina Marine offshore field was discovered in 1991 and production start up was in December 1997. Originally, the field development considered the three deeper intervals that were developed via a peripheral water injection scheme and a crestal gas injection displacement process. After a quite significant initial rate (around 50,000 BOPD), the field declined quite rapidly and it was necessary the installation of gas lift valves on all wells. In 2005, aiming to reduce the inevitable rate decline, a new level was opened to production via the recompletion of three deeper wells into the shallower and low permeability 3A reservoir [Ref.1[. This interval is characterized by the presence of thin silt and shale layers that decrease the vertical permeability strongly. The 3A Sandstone reservoir was initially produced in natural flow between the end of 2005 and august 2006, although the three wells were completed with gas lift mandrels (Fig. 7, Fig. 8, Fig. 9). Due to the low permeability (2–7 mD), after first year of production, level 3A in Kitina field had progressively declining production heading to a marginal-economic scenario. At the beginning of 2007 the production was:KTM W6 ST - 160 BOPDKTM 107 - 130 BOPDKTM 111 - 300 BOPD

Production of heavy oil with an artificial lift system is a puzzling problem due the hydrodynamic conditions prevailing inside and surrounding the pumping system. The aim of this paper is to present an application on ESP PCP of a system that has an impact on the oil viscosity surrounding the ESP PCP unit and as a consequence improving the production performance, the ESP PCP pump efficiency and run-life. The theory is based on the impact of convection currents on the diffusion of the temperature in high viscous oil inside a pipe. A case history will be presented on the ZAM-408ML, a TAML6 multilateral well producing from level B of the Zatchi field, offshore Congo. Introduction Zatchi Marine is an offshore field located about 25 km from the Congolese coast (fig.1). The field, developed in 1980 presents 5 oil bearing levels named A, B, C, D and E. Level A has currently no economical value since it is gas bearing. While the oil bearing levels C, D, E are producing from several years, level B, after very short episodes of production in the past was put in production in 2007 via the multilateral well ZAM-408ML. The level B, object of the paper, is a complex heavy oil reservoir with a primary gas cap and the presence of a bottom aquifer. The oil has a very high density (15°API) and is very viscous (13000 cP @ 34.5°C) probably due to the low reservoir temperature (about 35°C). This level is composed of sand, shaly sand, dolomite and shale (fig.2). The average reservoir permeability is greater than 1Darcy. Three wells have been drilled in the B level since 1991: the first one, ZAM-116 (vertical well with conventional completion), produced a maximum of 130 bopd (lifted by a sucker rod pump with a surface motor); thereafter, the ZAM-406 (horizontal well) produced at the beginning 440 bopd but the oil rate dropped rapidly due to a severe gas coning phenomena; the last one, ZAM-111ST (horinzontal well), peaked briefly up to 285 bopd. This brief overview depicts the reservoir B production complexities which in summary:the heaviness and the viscosity of the oil,The severe problems of gas coning and cresting which reduced drastically the progressive cavity pump efficiency. The multilateral well ZAM-408ML represents the forth well which is attempting the production of such reservoir. The well architecture and trajectory was designed to optimize reservoir recovery, productivity index while reducing the drawdown at the wellbore to avoid gas coning phenomena. In parallel, it has been decided to develop an innovative system to improve the ESPCP performances by increasing and homogenising the temperature distribution around the artificial system planned to be installed. The original scope was not to improve the well productivity, but only to have a better handling of the flow at the pump interface and maximizing the pump efficiency.

The Zatchi field, located in the Lower Congo Basin offshore, is a multi-layer reservoir of Cenomanian/Albian age operated by Eni Congo in partnership with Total Congo. The "Zatchi B" reservoir is a 30 m thick sand characterized by a large accumulation of heavy and highly viscous oil (15° API, 1000 cP) trapped in the marine-transgressive sands of the "Gres de Tchala" formation. Three aspects make the successful development of such reservoir an extreme challenge: the presence of both bottom water and a gas cap, the very low reservoir pressure, the very high viscosity of the oil. As a matter of fact, over the 19-year life of the field, only three wells were put in production from the "B" layer, with not satisfying results due to the heaviness and viscosity of the oil and the severe problem of gas coning and cresting. The multilateral technology generally allows increasing the reservoir exposure with fewer wellbores, reducing and spreading the drawdown along the drains reducing the potential for coning. For this reason, in order to improve the reservoir drainage reducing times and costs, the layer B was selected as the optimal candidate for the first multilateral well in the Congo basin: well ZAM 408 ML. This paper will review the Zatchi B reservoir history and development challenges with a focus on the multilateral well reservoir modeling, the TAML6 completion and ESP artificial lift design. An innovative system for the ZAM-408ML ESP PCP efficiency improvement will be also presented. Furthermore, the challenges encountered during the operations in terms of reservoir properties sampling, operations geology, drilling, completions and production will be discussed in detail. Introduction Dwindling oil supply, high energy prices and the need to replenish reserves are encouraging oil companies to develop all the assets that were temporarily parked for years either because too technological challenging or because not economically interesting. A huge number of "non conventional" oil reservoirs have been discovered worldwide, but only a small percentage of them is producing or is under active development. Most of the world's oil resources are heavy, viscous hydrocarbons that are costly and difficult to produce and refine. In particular, heavy oil (density lower than 22.3 °API), extra heavy oil (density lower than 10° API) and bitumen make up about 70% of the world's total oil resources of 9 to 13 trillion bbl [Ref. 1]. Heavy oils have become recently an important theme in hydrocarbon industry with an increasing number of operators getting involved or expanding their plans in this peculiar market. Many countries are moving now to increase their production, revise reserves estimates, test new technologies and invest in infrastructure to ensure that their heavy oil resources are not left behind. Eni Congo, operator of the offshore Congo Zatchi field participates to this challenge. The case history presented in this paper deal with both technological and economical challenges discussed above: a pilot TAML6 multilateral well in the complex heavy oil Zatchi B reservoir located in the offshore Congo.