This paper describes the successful combination of different stimulation techniques during the development phase of an offshore field in Congo. A total of four wells were drilled and completed during 2008-10. The target reservoir, the Sendji carbonates, has a total thickness of 150-170 vertical meters with an interlayer of ten meters. It is composed of silty-shaly dolomitic and quarzitic sandstone with interbeds of shale and sand grading to sandstone and silt with dolomitic cement characterized by very poor petrophysical properties. Laboratory testing with cuttings showed that formation is more than eighty percent soluble with fifteen percent hydrochloric acid. The typical well has an average azimuth and inclination of 60 and 350 degrees respectively, in the target reservoir. A good quality cementation job of the casing was required in order to ensure isolation from the aquifer. The well completions are both open and cased hole multistage fracturing completion systems. Selected zones of varying lengths were hydraulically fractured by using proppant / seawater-based borate crosslinker fluid or by using twenty percent delayed, viscoelastic and straight acid. Two wells were stimulated by means of proppant fracturing while the other two by acid fracturing. Due to upper / lower water zones with no bounding beds, it was important to define formation mechanical properties for fracturing designs in order to avoid fracturing into water bearing layers. A Mechanical Earth Model (MEM) was created by using sonic anisotropy measurements, modular dynamic test results, and other common electrical logging data together with drilling parameters. The detailed study of design methodology, different stimulation fluids and operation sequences are described. Particular attention will be given to the comparison of well responses to multi-stage proppant and acid fracturing techniques.

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe management of producing wells activated with ESP pumps has to take into account several problems: limited pump run life, production losses due to multi ESP failure and shut in wells.• pump run life increase not quantified due the test's short durationThe advanced information provided to the decision makers brought additional benefits to oil company leading to early production recovery, improvement of well inflow and outflow performance knowledge.The Smart Alarms approach can be also applied to other well typologies and data sources.

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. Large quantities of reserves can be found in low permeability, consolidated, formations and new techniques are being investigated to improve the economic return of completing these formations. The Kitina Field, offshore from Pointe Noire, Congo, is one such field. Deeper sands have been produced to economic depletion and the operator is looking for alternative production intervals. The targeted reservoir is the 3A Sand at approximately 2200 meters TVD. The reservoir is a very heterogeneous lithology with varying quantities of siltstone, sandstone and calcite. The intervals of better porosity show a decrease in clay content, but the good "sands" can be either dominated by quartz or calcite with substantial variations with each meter of height. Three candidate wells were selected for placing multiple propped fractures using a technique that has been used for six years in North America. This technique utilizes a series of mechanical packers and frac ports that are sequentially shifted "on the fly" allowing continuous placement of more than one hydraulic propped fracture without shutting down the pumping equipment. During April to June of 2007, eight hydraulic propped fractures were placed in three re-completed, cased-hole wells in the Kitina Field with very encouraging production increases. During the first 90 days of post fracturing production, a production increase of 200% was achieved. This paper will discuss the steps that were taken to place these propped fractures from an ocean going tender barge using skid equipment and recommendations for the future applications of this stimulation technique. Introduction The Kitina Marine offshore field was discovered in 1991 and put on production in November 1997. Originally, the field development considered the three deeper intervals:2A - Limestone,1A - Sand with carbonate cementing,1B - Limestone. The three reservoirs 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. The recovery factors vary between 15% of the 1B reservoir to around 25–30% of the 1A and 2A reservoirs. The platform has gas lift installed on some of the completions and others produce in natural flow. Production of the platform was 7,000 BOPD prior to the fracture stimulation.

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.