During the past decade, multiple transverse fracturing in horizontal wells has been applied so successfully in onshore low-permeability reservoirs that it is becoming the standard completion practice in many areas. The reasons for the success of this technique vary, but the two main reasons are related to the undisputed effectiveness of hydraulic fracturing as a production enhancement technique and the relatively low cost of pumping services in onshore areas. Success and industry eagerness for process/cost optimization have contributed to many technological improvements in the multistage completion process allowing sequentially executing several fracturing treatments in a single pumping operation. Nevertheless, the high direct and indirect costs and the risks associated with offshore operations have traditionally been limiting factors in spreading this technology to offshore applications. Sometimes, the misplaced perception of hydraulic fracturing as risky and costly operation prevented, rather than encouraged, its application in marginal offshore oilfields. Recent increases in oil prices and the success in onshore applications have encouraged the use of hydraulic fracturing in offshore applications. This study documents the successful effort of taking these techniques to the offshore environment. Transverse fracturing with multistage completion concept— with properly engineered design of well trajectory—can make the difference between the economic success or failure in the field development of low-permeability reservoirs. This study used multidisciplinary and integrated approach to design and execute the treatments, involving reservoir, production optimization, and fracturing engineers from the early stages of well planning to construction. The multilayer Foukanda field, located 52km offshore from Pointe Noire, Congo, has a low permeability and virgin target that was considered noncommercial after discouraging results of two wells. Based on the production results of three cased-hole wells in an analogous field where multiple propped fracturing was applied, the operator decided to drill an open-hole horizontal well that was to be multi-fractured. The initial 90 days average production of this Foukanda well was more than 2500bbl/day. This production rate was double the simulated rate of a vertical well and opened a wide range of further developments both in Foukanda and in other analogue fields in the offshore Congo. Introduction The Foukanda Marine field is located, 20 km to the north of the Kitina platform and 52km to the west of the city of Pointe Noire. Average water depth is around 100 meters. The field was discovered in 1998 by the well FOKM-1. Production started on June 2001. In the same year one well was drilled in the reservoir D but, due to very poor reservoir characteristic this level was abandoned and the well was recompleted on the shallower reservoir B4. The low permeability reservoir D (less than 10 md) was therefore abandoned and only the reservoir B4 and B7 put on production. In the first months of 2007 Foukanda field had a production potential of about 3000–3500 bopd with 6 producer wells (5 in the reservoir B4 and 1 in the B7) and 2 injector wells (2 in B4 and 1 in B7).

Perforations provide the communication between wellbore and formation resulting in a communication path both for injected and produced fluids from the reservoir. Many perforation parameters such as shot phasing, charges size, shot density, type of gun and length of interval play an important role in the correct execution of a fracturing job. Those parameters have to be engineered to guarantee easy formation breakdown, minimize near wellbore restrictions (or tortuosity) and be big enough to prevent proppant bridging while considering fracture treatment size, proppant concentration, proppant size and treatment flow rate. Ideal fracture initiation perforations would create a minimum injection pressure initiating a single fracture (not for shale gas reservoirs) and generate a fracture with minimum tortuosity at an achievable fracture initiation pressure. Best perforation practices are important during the decisional and designing phase but have to be confirmed by field experience even in well known reservoir where formation heterogenity, well deviation, local stress anomalies, cement bound and many other factors can result in unexpected behaviors that could compromise the success of the stimulation treatment. In the following paper a briefly description of perforating theories and different field experiences are reported showing test results executed for a better perforation strategy. Unexpected deviations both from theory recommendations and from field analogies were analyzed as well as successful and unsuccessful remedial solutions in cases of injectivity issues.

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.

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

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.