The results of stimulation treatments in southern Mexico's carbonate reservoirs have been significantly improved using a new fiber-assisted, self-diverting acid system. These reservoirs are thick, deep, and hot. Depths are usually greater than 15,000 feet, bottomhole temperatures reach up to 350°F, and permeabilities range from 1 to 1000 mD within the same interval. Wells are typically completed with multiple perforated intervals. In the past, high-viscosity diverting fluids have been used to improve zonal coverage during stimulation treatments. Despite repeated treatments during the life of the well, in many cases, post-treatment logs show that the treatment was not effectively diverted to lower permeability, less productive intervals. To overcome these challenges, we introduced an innovative degradable diverting acid system combining the properties of viscoelastic diverting acid (solid-free) and degradable fibers to southern Mexico. This, combined with a rigorous candidate selection process, resulted in improved zonal coverage, increased oil production, and higher ultimate reserve recovery. Maximizing oil production using this diverter system requires a detailed understanding of the petrophysical properties of the reservoir and production history. This information helps determine treatment volumes and the volume and number of diverter stages. Wells with the highest permeability contrast are often the best candidates. In many cases, producing from natural fractures depends on correctly determining the number and volume of the diverter stages. The experienced gained from treating more than 10 wells has resulted in the development of clear guidelines with respect to the treating fluid, volume, and number of diverter stages. On average, the guidelines have resulted production increases of 1,500 BOPD. By applying the treatment guidelines with an effective diverter fluid, operators can significantly increase oil and gas production in previously stimulated or new wells within naturally fractured carbonate reservoirs.
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.
Summary Asphaltene precipitation is a common phenomenon in mature reservoirs that seriously impairs oil production. In high-temperature (HT) fractured carbonate reservoirs, the situation becomes critical when asphaltene precipitates at reservoir conditions, blocking the production channels and starting a cycle of production decline in which additional pressure drop increases the precipitation of the asphaltene fraction. Therefore, it is essential to make an early diagnosis of the problem and deliver an optimal solution to avoid further production decrease. A proper diagnosis regarding the point of precipitation along the production path requires a complete analysis of the well's production behavior and reservoir characteristics. To avoid asphaltene precipitation inside the rock matrix, different methods can be applied: maintaining reservoir pressure above the asphaltene-onset pressure, avoiding coproduction of incompatible reservoir fluids, adjusting artificial-lift conditions, or injecting solvents with inhibitors or dispersants. In two mature fields in southern Mexico that have been producing since 1995, an operator needed to determine where the asphaltene precipitation was occurring. An integrated diagnosis work flow was instrumented that included the creation and analysis of the asphaltene-phase envelope plus an asphaltene-onset screening test by use of a solids-detection system (SDS). After coupling screening results with a pressure/temperature flowing survey, it was identified that asphaltene precipitation occurred inside the reservoir when the bottomhole flowing pressure dropped below a critical level. To address the organic deposits and unstable pressure behavior successfully, asphaltene-precipitation characterization was essential. In some cases, a decrease in oil production after executing unsuccessful matrix-cleanup treatments with solvents results from a misdiagnosis of organic precipitation or a lack of knowledge about flocculation and precipitation causes. To avoid this problem, a new methodology for the inhibition-treatment design was added to the diagnosis work flow; this methodology includes a new adsorption-type asphaltene inhibitor as part of the matrix-cleanup treatment. As a result of this diagnostic-solution work flow, an optimum bullheaded inhibition treatment was determined and applied to the candidate wells. In all study cases, the time lapse between inhibition treatments was extended by 60 days on average, resulting in steadier oil flow rates plus significant reduction in well intervention and deferred production costs. In addition, the post-treatment results showed that, in 50% of the documented interventions, the inhibitor treatment improved overall production performance by at least 10%. The systematic engineering work flow presented in this paper includes the diagnostic procedure, data from laboratory testing, chemical selection, and treatment application. Subsequent treatment results enhanced the field operator's understanding of asphaltene precipitation in the formation matrix and provided more insight into maximizing oil production with specialized technology solutions that used a novel adsorption-type asphaltene inhibitor.
Operators began evaluating the shale gas block in Central China since Dec 2010. During their exploration and appraisal phases, 3 horizontal wells were drilled. Their challenges consisted of hard, abrasive formations with kicks, losses, stuck pipe and over pressure. The problems were amplified by high geological formation dip, faults, and stratigraphic uncertainties. As a result, they were unable to achieve efficient drilling using conventional motor bottom hole assembly (BHA), that made it difficult to run casing, and multiple geological side-tracks were the norm. Naturally, these wells exceeded authorization for expenditure (AFE) curves, requiring an average duration of 200 days per well. This paper features the challenges and lessons learned along with the unconventional approaches that were employed to address these challenges. Four key categories of the process were identified:They consisted of emerging technologies such as a hybrid and robust rotary steerable system (RSS), real time rate of penetration (ROP) optimization and high resolution real time logging while drilling (LWD) image data tools. In addition, drilling and best practices adopted were managed pressure drilling (MPD), high dog-leg-severity (DLS) curve with smoother borehole, and low cost rotating blowout preventer (BOP) with higher revolution per minute (RPM). In the absence of 3-D seismic data, 2-D seismic data combined with LWD data were used. Integrated Operations & Innovative Commercial Contract with local drilling service contractors had made a big impact in terms of faster well delivery and overall cost saving. Another step change was with the performance based commercial contract that helped to attain the ultimate goal to meet health, safety and environment (HSE) and time requirements.At the end of 2013, 11 horizontal wells were drilled and completed. Amongst these, one well was categorized as Top Quartile and four were Best-In-Class. Additional highlights include significantly reduced geological side-track; quadruple footage drilled per day and the reduction in drilling cost. Average well duration was significantly cut to 110 days.These accomplishments consequently enhanced the drilling schedule sequence with longer horizontal wells being planned and greater confidence of predictability and repeatability.The paper will conclude with a summary of comparative learning statistics. The team believes that this is a big step towards delivering Best-In-Class wells in complex geological structure. The next step is to realize the ambition of factory drilling at a further reduced cost to tap the unconventional plays in the Sichuan basin, and bring cleaner fuel to Central China as a replacement of coal.
Extracting oil from horizontal wells in naturally fractured carbonate reservoirs (NFR) is challenging. To properly evaluate the formation, a solution was developed that integrates key formation evaluation technologies with stimulation systems and which has proved to be effective in holistically solving such challenges.The holistic well analysis included evaluation of static data by integrating all available openhole data and special logs. To locate the most productive zones, fracture characterization was conducted using advanced interpretation techniques. Dynamic evaluation also included the analysis of measurements obtained using a formation tester. An integrated technical solution included a proper matrix stimulation design that considered all these data to reduce formation damage and connect the fracture networks.This study successfully confirmed the presence of hydrocarbons in the T field in southern Mexico for the first time. Production not only exceeded expectations, but also added reserves to this new exploration area, aiding in the development of the Upper Cretaceous formation referred to locally as the KM.
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