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.
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.
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.
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