In early 2008, Total E&P-USA sidetracked the Mississippi Canyon 243 #A2 well on its "Matterhorn" TLP, in deepwater Gulf of Mexico. A pre-project geomechanics study identified that the mud weight/fracture pressure window in the depleted and highly unconsolidated 'A' reservoir was very narrow, creating a strong potential for mud losses during drilling and cementing the 7" liner. The risk of losses was a primary concern since the well would be frac-packed, and if a competent cement column did not reach a sufficient height, the ability to fracture the reservoir would have been compromised. To mitigate this risk, the decision was made to drill through the depleted reservoir using a 'flat rheology' synthetic-based fluid, engineered with a high concentration of bridging particles to impart a strengthening effect on the formation. The 'designer fluid' allowed the reservoir to be drilled through successfully, and the 7" liner to be run and cemented with full returns. Analysis of the frac-pack data showed that the formation breakdown pressure was lower than the wellbore pressures experienced while drilling and cementing the liner, suggesting that the designer fluid improved the fracture resistance of the formation. The results imply that using such a designer fluid can have a strengthening effect on depleted/unconsolidated formations, in which some operators have had limited success applying wellbore strengthening techniques. The implication for the industry is that this technique can and should be considered on wells with similar challenges and risks as the Matterhorn A2 well. This paper will describe the approach taken in the laboratory for the fluid design, as well as operational practices to apply the treatment on location. A post-mortem analysis will compare formation breakdown pressures taken from the fracturing operations to actual wellbore pressures experienced while drilling and cementing, to demonstrate that a strengthening effect was realized. Introduction Total E&P USA conducted sidetrack operations on the A2 well to restore production that was impaired after prolonged shutdowns due to Hurricanes in recent years. The operations included: re-entering, de-completing, side tracking and re-completing the well. The operations were done with a heavy work-over rig installed on the TLP, and used a 'flat rheology' synthetic-based mud (SBM). A geomechanics study had been conducted prior to the sidetrack, and the analysis identified that a strong potential existed for mud losses in the depleted and highly unconsolidated 'A' reservoir due to the mud weight required (and associated ECD) to control the breakout of the cap rock shales above - a common scenario faced by operators during in-field drilling operations. According to the study, the mud weight/fracture pressure window had essentially disappeared.
The South Region of PEMEX in Mexico produces 530,000 bopd from mostly mature, naturally-fractured carbonate reservoirs. The majority of the well interventions in the area present complications, due to a combination of extreme operational conditions, variety of reservoir rocks and fluid environments, and complex well configurations required to produce from large intervals in different flow units, many supported by active aquifers and secondary gas caps, that eventually reduce the production of oil as the water production and gas production increase. Rigless stimulation and maintenance well operations have been recognized for decades as efficient and cost-effective production enhancement enablers in the area. As the fields mature and the well interventions become more challenging, there is a higher demand on the operator side to successfully pinpoint the intervals and execute treatments that overcome unknown downhole parameters with confidence, maximizing success and avoiding additional remedial work. A new approach, incorporating real-time, coiled tubing-deployed, fiber optics monitoring, was implemented in three well interventions in southern Mexico. These included: (a) the isolation of a high-water producing interval in a low-pressure reservoir using an inflatable packer; (b) a matrix stimulation requiring the accurate placement of fluids and diversion stages; and (c) the perforation and testing of several intervals in a gas injector well. Real-time down-hole measurements of performance have been found to be an excellent option to improve the success rate in the well interventions in southern Mexico, allowing capturing unique quantitative feedback from the well, to be able to act with a greater degree of precision to increase production. Coiled tubing-deployed fiber optics proved to help the operator to improve efficiency and to optimize intervention performance with confidence in real time.
In early 2008, Total E&P USA sidetracked the Mississippi Canyon 243 #A2 well on its "Matterhorn" tension-leg platform (TLP) in the deepwater Gulf of Mexico. A preproject geomechanics study identified that the mud-weight/fracture-pressure window in the depleted and highly unconsolidated "A" reservoir was very narrow, creating a strong potential for mud losses during drilling and cementing of the 7-in. liner. The risk of losses was a primary concern because the well would be frac packed, and if a competent cement column did not reach a sufficient height, the ability to fracture the reservoir would have been compromised. To mitigate this risk, the decision was made to drill through the depleted reservoir using a flat-rheology synthetic-based fluid, engineered with a high concentration of bridging particles to impart a strengthening effect on the formation.The designer fluid allowed the reservoir to be drilled through successfully and the 7-in. liner to be run and cemented with full returns. Analysis of the frac-pack data showed that the formation-breakdown pressure was lower than the wellbore pressures experienced while drilling and cementing the liner, suggesting that the designer fluid improved the fracture resistance of the formation. The results imply that using such a designer fluid can have a strengthening effect on depleted/unconsolidated formations, in which some operators have had limited success applying wellbore-strengthening techniques.The implication for the industry is that this technique can and should be considered on wells with challenges and risks similar to those of the Matterhorn A2 well. This paper will describe the approach taken in the laboratory for the fluid design, as well as operational practices to apply the treatment on location. A postmortem analysis will compare formation-breakdown pressures taken from the fracturing operations to actual wellbore pressures experienced while drilling and cementing, to demonstrate that a strengthening effect was realized.
Total operate a field located 150 kilometers off the Niger Delta at a water depth of 1,400 meters. This field is the first deep-offshore development involving light oil with high gas content. In the field's Miocene reservoir the fluid is under saturated (~ 80 bar) and in 'critical conditions', i.e. the gas and liquid hydrocarbons are in a single phase, at high pressure and temperature.Several turbiditic-type reservoir layers are developed with 22 oil producer wells, 20 water injector wells and 2 gas injector wells.Reservoir G is a lobe sand body with good petro-physical characteristics (Permeability = 300 to 500 mD, Porosity ~ 20%). This reservoir is developed with 2 producer wells, well 7 and well 9, completed with frac-packs, and 2 water injector wells for pressure maintenance.In September 2009, six months after first oil, well 7 and well 9 lost 70% of their potential following the decline of their productivity index. The impact was 20,000 bpd production shortfall. This paper describes the investigation process that was conducted to identify the cause of the decline. The process included pressure transient analysis, geochemical analysis, core flooding tests and scale modeling. A trial and error approach was adopted when designing well intervention in order to get as much information as possible and firm up the most realistic cause of production damage. This paper also highlights the fact that a proper diagnostic requires a multi-discipline approach, an open mind and a comprehensive risk analysis.
Carbonate reservoirs in the southern region of Mexico are characterized as deep, hot, and naturally fractured. Most wells in Cretaceous and Jurassic carbonate formations are acid stimulated at the time of completion and periodically during the life of the well to combat damage mechanisms that occur during drilling and production. These wells are typically completed with multiple perforated intervals. Not all the intervals have the same density of natural fractures, some sections having no natural fractures. This creates a very high permeability contrast estimated to be as high as 1000:1 in extreme cases. Also, the reservoir pressure varies between the different intervals as a result of simultaneous production from zones with widely varying permeability. The contrasting permeability and reservoir pressure constitute a major challenge at the time of stimulation treatments in terms of achieving uniform zonal coverage and fluid penetration in all treated zones. The treatments are bullheaded, so effective diverting fluids are required to ensure the complete vertical coverage of the zones of interest. The diversion, however, must be temporary and nondamaging to the reservoir and the natural fracture network. To meet this challenge, a degradable acid-diversion system has recently been applied in matrix acidizing treatments in southern Mexico. The diversion system combines the viscosity-based effect of self-diverting acid with particulate-based diversion provided by degradable fibrous material. The combination functions synergistically to provide superior zonal coverage of matrix treatments under extreme conditions. In acid fracturing applications, the new system reduces leakoff in fissures and natural fractures, which leads to a more efficient spending of the acid and therefore longer fractures. The degradable nature of the fibers and viscoelastic surfactant result in no post-treatment damage. Furthermore, the fibers produce a weak acid while dissolving in the presence of water at bottomhole temperature, continuing to stimulate the well as they degrade. This paper presents three case studies in which superior results were obtained by using the new diverter when compared to results achieved in offset wells in the same reservoirs and under similar conditions conventionally stimulated. Production increases in excess of 100% have been achieved where conventional treatments have failed to increase production. Lower production decline and higher flowing pressure have also been observed. The latter is interpreted to be the result of the fluid diverting from highly fractured and depleted zones into undrained lower-permeability with fewer natural fractures.
Since 2003, the main challenge of selective matrix treatments with coiled tubing (CT) has been to manage the severe corrosion rates of CT strings with large acid volumes and long exposure times to hydrochloric acid (HCl), resulting in reduced pipe life. Generally, the average volume required per job is 300 bbl of 15% to 20% HCl, depending on the bottomhole conditions and damage mechanisms; severe material losses of carbon steel coiled tubing string grade 90,000 psi have been regularly measured above 0.20 lb/ft2. Our local stimulation team has developed an engineering workflow that consists of several stages and can reduce corrosion rates below 0.05 lb/ft2. A laboratory database was built to perform corrosion tests under time and temperature conditions and evaluate available corrosion inhibitors. The database allows the selection of the inhibitor and concentration range for each application. To reinforce the quality control, field preparation of acids is monitored and samples are tested to compare with laboratory design. Finally, measurements of coiled tubing wall thickness give an estimated value of material weight loss. As a result of the implementation of the workflow, average pipe life has been extended from 1,200 to 3,000 bbl of 15% HCl pumped.
The ultimate objective for cementing a casing string is to achieve long-term integrity of the well. This can be achieved through long-term zonal isolation between the penetrated formations with appropriate mechanical properties, low permeability, and shear bond strength properties provided by the cement sheath placed in the corresponding annuli. Experiences in the Hassi-Messaoud field have shown that zonal isolation is a very complex problem for some formations such as the LD2 zone, which exhibits, in some cases, corrosive fluids and highly saline formations as well as lost circulation zones. Cementing operations are critical and the need for cementing systems capable of solving these problems is crucial. This paper focuses on the factors that have contributed to the potential failure of the existing cement system. Stress modeling has been used to select the appropriate cement system to overcome the challenges faced by the cement sheath in this type of environment. Stress analysis calculations, combined with mechanical properties testing of the cement system, has suggested the use of a novel cementing technology. This new system has been able to solve these problems to provide flexibility, improve corrosion control, expansion properties of the set cement, reduce the chances of microannulus creation, and therefore avoid overpressurization of the annulus casing. To ensure correct cement placement in the lost circulation zones, this slurry system has been successfully combined with fibers specifically engineered for cement slurries. This technology has been a cost-effective solution for cementing 12 1/4-in sections in the Hassi-Messaoud field and 8 1/2-in sections in the Berkaoui and Hassi-Guettar fields. Field results have proven that significant workover costs, up to USD 1 million on wells in production, can be saved with the application of this technology. Introduction and Hassi-Messaoud Field Characteristics Zonal isolation is one of the primary objectives of cementing a well and if not achieved, may result in fluids migration to surface, microannulus, annular pressure development and alteration of the integrity of the cement sheath. This problem, if encountered, can be time and money consuming for the operating company causing workover and remedial work extra costs. Algeria is a major hydrocarbons producer in Africa, producing currently 1,300,000 bbl/day of crude oil and exporting about 70 billion m3 of gas per year. By far the largest oil field in Algeria is Hassi-Messaoud, located in the center of the country, which produces about 350,000–400,000 bbl/day of 46o API crude, down from 550,000 bbl/day in the 1970s, but up from 300,000 bbl/day in 1989. The Hassi-Messaoud area contains an estimated 6.4 billion barrels, just below 60% of the country's proven oil reserves. It is expected to double production from the field to 700,000–750,000 bbl/day within the next 3 years. In order to satisfy the increasing market demand, the Hassi-Messaoud field is currently under important development. The Hassi-Messaoud field is characterized by a very thick sandstone reservoir covering an area of 2000 km2. The producing layers occur at an average depth of 3400 m and are located in the Cambrian Ra, R2 and R3. In the past few years, horizontal wells in Hassi-Messaoud field have started to be drilled in order to optimize the reservoir contact.1 In most cases a 7-in. liner is landed at a depth corresponding to the top of Cambrian Reservoir Ra, corresponding at a deviation of 45° and a 6-in. drain is drilled to target depth (TD) inside the reservoir Ra, R2 and R3 to a measured depth (MD) of an average of 4300 m, corresponding to a true vertical depth (TVD) of 3400m and an inclination of 89°. The 6-in. section across the Cambrian is then completed by production tubing in open hole (Fig. 1).
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