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Caillon, Didier (TOTAL E&P) | Groschaus, Benjamin (TOTAL E&P) | Matsiona, Wilfried (TOTAL E&P) | Boumba, Theben (TOTAL E&P) | Bledou, Manfred (TOTAL E&P) | Dupouy, Nicolas (Halliburton) | Ilyasov, Robert (Halliburton) | Reilly, Brett (Halliburton) | Quero, Philippe (Halliburton) | Stimatze, Russell (Halliburton) | Bhamidipati, Venkata (Halliburton) | Prudnikova, Antonina (Halliburton)
Abstract Moho Nord deep offshore field is located 80 kilometers offshore Pointe-Noire in the Republic of the Congo. The wells produce crude from the Albian age reservoir and lithology consists of alternating sequences of carbonates and sandstone layers with high heterogeneity and permeability contrast, including the presence vacuolar layers called "hyperdrains". This paper describes the application of a novel acid system and the methodology successfully applied to effectively acid stimulate the Albian drain. The combination of long perforation intervals with lithology and permeability contrasts, natural fractures, and the potential for asphaltene deposition resulted in adoption of a Modified Carbonate Emulsion Acid (MCEA) fluid system containing a solvent to provide asphaltene deposition prevention. The MCEA stimulation treatments were bullheaded from a stimulation vessel and an engineered diversion process was implemented for effective acid diversion using a combination of mechanical ball sealers and a degradable particle system (DPS). The selection of number of ball sealers and the DPS diverter design depended upon the interpretation of zone permeability profile from the logs, and the final distribution of perforations selected along the drain. A fluid placement simulator indicated low sealing efficiency of the ball sealers would lead to an overstimulation of the highest permeability areas. Subsequent simulations indicated that the DPS would provide better acid coverage with lower skin (S). Results and observations presented indicate that the decision to improve the acid diversion design and combine ball sealers with a DPS diversion technique to improve zonal coverage was validated. During the stimulation treatment execution, the high stimulation treatment efficiency was clearly apparent from the pressure responses to the acid and the diverter system which sealed off perforations and diverted the treatment to other layers with lower permeability. The MCEA also has proven to have self-diverting properties due to its high viscosity and low reaction rate which creates a better coverage of the drain, even with limited pumping rate, allowing live acid penetrating deeper into the formation. The production results reported from the 15 wells stimulation campaign (10 producers, 5 injectors) indicated that the productivity indexes (PI) exceeded expectations and resultant post-stimulation skin values ranged from −2.5 to −4.1. The Moho Nord deep offshore stimulation campaign yielded outstanding production results and showed significant validation for use of the MCEA system and the diversion methodology applied. On the producer wells the use of both chemical and mechanical diversion was valuable, as the DPS proved to complement the Ball Sealers for layers with lower injectivity and also at the high injection rates. High injectivity gain coupled with effective diversion was crucial for enhanced wormholing and good drain coverage.
An exciting technical visit to the Djeno Oil Terminal, a few kilometers south of Pointe Noire, attracted more than 20 YPs. The terminal’s technical director gave an interesting presentation on the facilities, followed by a plant tour. The Djeno terminal treats 250,000 BOPD, almost 90% of Congo production. It is the largest oil terminal in west Africa and the largest owned and operated by Total E&P. Two of the commercial oil blends sold from the terminal are the Djeno Melange and the Nkossa Blend. The visit was sponsored by Eni Congo and Total E&P Congo. The SPE YP programs have generated a lot of interest and motivation in Congo, with YP membership in the SPE Congo Section soaring from 2 to 32 in the past half-year.
The Congo Section came back to life in September 2006 after more than 7 years of pause. Energized by Tony Ogunkoya (SPE Congo Chairman), the section had a thriving start with a joint Young Professional and Main Board event: “Developing Young E&P Professionals To Solve the Big Crew Change,” held 22 September in Pointe Noire, Republic of Congo. Fifty-three people attended the meetings indicating a great interest in the subject and in SPE activities in Congo. As proof of such enthusiasm, the number of SPE members increased by a factor of 10 between September and November 2006.
The recent startup of Total's Moho Nord deepwater field, 47 miles off the coast of Pointe-Noire in the Republic of Congo, marked an offshore oil milestone for the country. The field began production on 14 March, representing the second phase of the overall Moho Nord project. The project's initial development, the Moho Bilondo Phase 1b field, started production in 2015. Total initiated both field developments in March 2013, and as an investment they are the Republic of Congo's biggest oil project ever. Phase 1b and Moho Nord produce from the northern portion of the Moho Bilondo license, and the recent field startup completes stage two of the license development.
Abstract A unique air-energized drilling fluid was developed that enabled all 13 wells in the development program of the Emeraude field, Offshore Pointe-Noire, Republic of Congo to be drilled with only 19-bbl downhole losses and zero non-productive time. The energized air-surfactant polymer drilling fluid used on the Emeraude field has potential for drilling similar depleted carbonate reservoirs in West Africa. The Emeraude field is a major hydrocarbon accumulation lying offshore Pointe-Noire, Republic of Congo below water 60 to 75 m deep. The 150 m thick reservoir is a complex sequence of interbedded silt and fractured carbonates with an average reservoir pressure of 0.4 to 0.7 sg equivalent pressure. Such low reservoir pressures present considerable drilling challenges, including efficient hole cleaning in inclined wellbores up to 53°, minimizing stuck pipe risk from excessive overbalance pressures in permeable and depleted formations, and minimizing downhole fluid losses in fractured carbonate formations. Over fifty previous offset wells, which were drilled with various types of drilling fluids, suffered from total losses and subsequent poor cement jobs, as well as high water-cut hydrocarbon production. The drilling program was very successful with very minimal downhole losses and zero non-productive time. Hole cleaning was excellent at all times as evidenced by low rotary torque, pick up and slack off weights while drilling and tripping out of hole. In addition, cementing operations were completed successfully with full returns, and initial production had zero water-cut. This paper details case histories from the Emeraude field 13-well drilling program, focusing on the design elements of the novel drilling fluid. Best engineering practices adopted to successfully drill these challenging wells also are described in detail.
ABSTRACT Dynamic Replacement is a ground improvement technique used for treating soft compressible cohesive soils. It has been used in numerous land projects and a number of offshore works with seabed as deep as 15 m below sea level. Recently, works of similar nature was carried out in Southeast Asia with the intention of exploring the possibility of treating soils in deeper waters. The pressuremeter test was used to verify the results and to estimate the soil parameters. INTRODUCTION Dynamic Replacement (DR) is a ground improvement technique developed by Louis Menard in 1975 for the treatment of soft cohesive soils. As shown in Fig. 1, in this technique a heavy pounder is systematically dropped a number of times onto specific points in order to drive granular material into soft compressible cohesive soils and to compact the driven material sufficiently to meet the project's design criteria. Dynamic replacement is a very cost effective, efficient and rapid method of treating soft soils and has been used in numerous land projects including the 2.6 million square meter mega soil improvement project of King Abdulla University of Technology in Saudi Arabia (Chu et al., 2009). Dynamic replacement or its counterpart ground improvement technique for granular soils, dynamic compaction, have previously been used for the treatment of soft or loose marine soils in offshore projects such as Brest Naval Port in France (Menard, 1974;Boulard, 1974; Renault and Tourneur, 1974; Gambin 1982), Pointe Noire in Gabon (Menard 1978), Uddevalla Shipyard Wharf (Techniques Louis Menard, 1975; Gambin 1982), Kuwait Naval Port (Gambin, 1982; Chu et al., 2009), Sfax Fishing Quay in Tunisia (Menard, 1981; Gambin 1982), and Lagos Dry Dock in Nigeria (Gambin, 1982; Gambin and Bolle, 1983) with seabed as deep as 15 m below seawater level.
Abstract The Azurite field development, installed in the Republic of Congo in 2009, utilized the industry's first Floating, Drilling, Production, Storage and Offloading (FDPSO) vessel to develop the field. First oil was achieved in August 2009 - only 4 ½ years after discovery. Although the FDPSO concept was talked about for many years, the Azurite project team made it a reality. The team, charged with aggressive cost and schedule targets, turned a " white board concept?? into a producing asset. This paper will discuss the key decisions made, focus on the reasons why they were made, and describe the challenges, solutions and lessons learned on this pioneering development. Introduction The Azurite field development, installed in the Republic of Congo in 2009, represented a first of a kind development utilizing the industry's first Floating Drilling, Production, Storage and Offloading (FDPSO) vessel. While there were many firsts and successes achieved on this project, lessons were learned, that if taken into consideration, could optimize the industry's next FDPSO. Discovery and Appraisal The Azurite field lies within the Mer Profonde Sud (MPS) block offshore Republic of Congo, approximately 80 miles offshore from Pointe Noire, Republic of Congo. Water depths across MPS range from 1100 - 2000 meters. The Azurite field was discovered in January 2005 with the Azurite Marine-1 (AZRM-1) well. The field was subsequently appraised in late 2005 and early 2006 with the drilling of the AZRM-2 and AZRM-3 wells. Each of the latter two wells was sidetracked (ST) to appraise the four fault blocks of the field. AZRM-2ST was also cored and production tested. Field Description The Azurite field is located in 1400 meters water depth. It consists of four major fault blocks and two main reservoirs. The reservoirs in the Azurite field were sufficiently deep and had limited areal extent such that they could be developed from a single drill center. This aspect yielded a significant advantage for Azurite, and ultimately impacted the preferred field development scheme. Development Timing In March 2006, at the end of Azurite's appraisal program, a small project development team was put in place to confirm Azurite's technical and commercial viability. If the field showed promise, pre-sanction engineering and capital project planning activities would be fast-tracked in order to sanction the project and preserve the possibility of an early first oil date. After only nine months of technical evaluations and project execution planning by the Azurite integrated project team, the team's preferred development scenario, involving the industry's first FDPSO, was proposed and sanctioned in December 2006. The project team was charged with delivering first oil in 2 ½ years. The challenge was on. The project team utilized a stage gate system to focus the team's engineering and project management activities. Lessons learned were captured continuously and formally documented after each stage gate was achieved. Some of the more noteworthy lessons learned that were captured along the way are shared in this paper.
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 119140, "Multiple Transverse Fracturing in Open Hole Allows Development of a Low-Permeability Reser voir in the Foukanda Field, Offshore Congo," by Alberto Casero, SPE, Loris Tealdi, SPE, Roberto Luis Ceccarelli, SPE, Antonio Ciuca, SPE, Giamberardino Pace, SPE, Eni; Brad Malone, SPE, Schlumberger; and Jim Athans, SPE, Packers Plus Energy Services, prepared for the 2009 SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, 19–21 January. The paper has not been peer reviewed. During the past decade, multiple transverse fracturing in horizontal wells has been applied successfully in onshore low-permeability reservoirs. The reasons for the success of this technique are related to the effectiveness of hydraulic fracturing for production enhancement and to the relatively low cost of pumping services onshore. Offshore, high direct and indirect costs and the risks associated with operations have limited the use of this technology. This study documents the successful effort of taking these techniques offshore. Transverse fracturing with multistage completion—with properly engineered design of the well trajectory—can provide economic success of field development of low-permeability reservoirs. Introduction The Foukanda marine field is 20 km north of the Kitina platform and 52 km west of the city of Pointe Noire, Congo. Average water depth is 100 m. The field was discovered in 1998, with initial production in June 2001. That year, one well was drilled in the D reservoir, but it had very poor reservoir characteristics, and this level was abandoned. The well was recompleted in the shallower B4 reservoir. The low-permeability D reservoir (less than 10 md) was abandoned. Successful fracture treatments in the Kitina field in May 2007 proved the possibility of obtaining economical rates from a marginal reservoir. It was decided to test the multistage hydraulic-fracturing technology on the previously abandoned D reservoir in the Foukanda field. Synergy from early cooperation among drilling, reservoir, and production-enhancement engineers proved key for the operation. An optimum process path was followed: reservoir assessment, selecting optimum fracture(s) configuration, providing input for the drilling plan, selecting the proper completion to allow optimum fracture(s) placement, and, finally, plan execution. The original plan on Foukanda was to drill a new vertical or deviated well with one or two fractures. Fracturing engineers suggested changing this plan and drilling a horizontal well and completing it with multiple transverse fractures. The deviated well was discarded because of complex fracture-growing issues, which, in the best case, could have transverse fractures that are not properly spaced, resulting in fracture/production interference. The advantage of having transverse fractures in a horizontal well is the possibility of proper spacing and deciding the optimum number of fractures that are required.
Abstract The Contract of the Subsea Production System Package was signed between TOTAL E&P Congo (TEPC) and FMC Technologies in July 2005. The FMC scope of work comprised the EPC for 2 manifolds (6 and 4 slots), 14 vertical Xmas-tree systems, the overall subsea control system located on the topsides (SCU, SPCU, HPU) and subsea as well as the work-over equipment required for the installation of trees. A second Contract was dedicated to the work to be performed in Congo on a base built by TOTAL E&P Congo and provided to FMC. One of the main challenges was for FMC to engineer and fabricate Xmas-trees with a 6 hour thermal autonomy before hydrate formation, with low production temperatures In order to avoid late surprises, an extensive test program was performed in Norway, prior shipment of the equipment to Congo. One manifold, one injection tree and one production tree were subjected to System Integration Tests(SIT), Shallow Water Tests(SWT), Xtree and Manifold Cool-Down Tests (CDT), Stack-Up Tests (SUT). Despite the fact that Moho Bilondo was the first deep water offshore development in Congo, the installation of manifolds and the first trees and jumpers went very smoothly. Part of this success was the result of a detailed interfaces management. Finally, the constant presence of Company personnel in Congo enabled the project to maintain Quality and HSE including for the local subcontractors who had never worked in the past with such equipment and materials. Introduction: Presentation and specificities of the Moho-Bilondo Subsea Production System Presentation of the SPS package The SPS package of Moho-Bilondo covers the permanently installed subsea equipment, plus the related tools for their installation and for intervention, and the set-up of a SPS base in Congo for the preparation of equipment before installation, maintenance of the tools and fabrication of the production well jumpers. After a competitive tender, two contracts were signed with FMC Technologies in the summer 2005; an EPC contract for the engineering, manufacturing, testing and transport of the SPS equipment and an IAC contract for all local work in Congo. The Moho Bilondo subsea production system consists of production wells arranged in a close clusters around two manifolds, one at the Bilondo field, and one at the Mobim field. Each manifold is connected to the Floating Production Unit (FPU) via two thermally insulated flowlines, a gas lift umbilical and a control umbilical. The manifolds have a dual header configuration with a pig loop, allowing round trip pigging from the FPU. Water injection wells are positioned close to each cluster. See figure 1 As a parallel activity, the construction of a SPS base within TOTAL Base Industrielle in Pointe Noire was launched to host FMC customer support personnel as soon as the first equipment was delivered. Moho Bilondo had a tight planning with the first manifold delivery planned at contract signature plus 14 months and keeping in line with the planning was a continuous struggle. The first pieces of equipment (the manifold foundations) were delivered on time, early in 2007, and were installed successfully. In general the delivery schedule has been respected, causing no disturbance to the installation planning, except for the Mobim manifold whose delivery date had to be postponed by a couple of month due to a technical incident which occurred during the fabrication. Concerning the IAC contract, even though the installation campaign went generally fine, some stand-by time on the rig and UFL installation vessels could have been avoided.
Abstract Foukanda permit is situated offshore Congo to the north of Kitina platform and to the west of Pointe Noire town. The Foukanda platform comprised a drilling template with eight slots, all of which were drilled through a 30-in. conductor casing that was laid on sea-bottom and connected to the platform's drilling template, and all were directional wells. The operator wanted to drill another well to explore another structure of the reservoir, but this was not possible with the existing template. The custom way of securing an extra slot was that which involved setting of a 30-in. diverter with 2° angle to the sea bottom, conventionally drilling some length of new hole with a 26-in. roller cone bit and then running and cementing a 20-in. casing through this 30-in. diverter and with free returns to sea bottom. This method had a negative aspect, which was the difficulty of re-entering the 26-in. hole with the 20-in. casing because of the sag of the conventional drilling assembly at the exit of the 30-in. diverter. To resolve this problem, the operator opted for an innovative drilling technique: drilling with casing. A 24-in. casing drilling bit was manufactured on purpose and was run through the diverter on a 20-in. casing string which drilled 66 m of new formation at 2° inclination and with returns to the seabed. The casing was cemented in place and the casing drilling bit was than successfully drilled out with a roller cone bit. This operation enabled the operator to secure the extra slot, to get out of the existing wells trajectory and to save the costs associated with difficulties to re-enter the hole. In this paper, the authors will describe the casing drilling bit technology, the planning of operations, the implementation, and the results compared to conventional drilling. Introduction At the Foukanda field offshore Congo (Fig. 1), the operator faced a frequent dilemma of needing to drill new wells from an offshore platform when all the slots on the seabed template have been drilled. The quandary is even more pronounced in today's environment with maturing offshore oilfields and the compelling need to increase production from new structures. One of the more obvious solutions to this problem is to drill new wells alongside existing wellbores, thus negating the use of the sub-sea template. Since all or most of the existing wells are deviated, this solution requires measures to be taken against collision with the template or the existing wells. Consequently, precise positioning of the well is crucial, which is the primary reason the template is used in the first place. Furthermore, directional control of the surface section may also be required. This is the problem the operator was faced with the Foukanda operation. The Foukanda platform has a sub-sea template with eight available slots, as shown in Fig. 2. All eight wells were drilled and most of them were deviated in different directions (Fig. 3). The operator wanted to drill another well, thereby increasing production of the field, but as described above, few options were available.