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.

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.

Many oilfields in southern Mexico produce from naturally fractured carbonate reservoirs with a high water cut. The majority of the remaining reserves are in the formation matrix. The objective when stimulating these wells is to connect the formation matrix with existing fractures. However, in some cases, the water-oil contact is close to the producing interval and the salinity of the water is more than 350,000 ppm. This results in rapid scaling and loss of production. The time for the scale to plug the well is a function of the volume of water produced.The challenge in these wells is not only to selectively divert the treating fluid away from the natural fissures/fractures-thief zones-invaded with water, but also to reduce water production from the natural fractures and fissures after the treatment. To treat the formation matrix, the diverter fluid must reduce the high permeability of the water-saturated intervals without impairing the permeability of the oil-producing intervals.Historically, in southern Mexico, viscoelastic surfactants have been used as main diverter for acidizing treatments. However, these systems have been successfully implemented in other applications. The surfactant also acts as a disproportionate permeability modifier (DPM) as the water cut is reduced after the treatments. The water cut of wells stimulated with treatments including the surfactant-based diverter remains below 10%, and the wells typically produce over 1,000 BOPD for more than 200 days before the scale has to be removed. The water cut of wells treated conventionally in the same field is typically above 60%, and the wells produce for fewer than 50 days after being treated before plugging with scale. The ability of the solids-free surfactant-based diverter to limit water production has made possible developing a field that previously was considered uneconomic due to the saline precipitation into the formation. Overview of ScalingScaling can be a serious problem for the oil and gas industry (Zhang et al, 2015). Scaling is the deposition of a mineral salt on processing equipment, and it is considered a result of supersaturation of mineral ions in the process fluid. This supersaturation of ions is caused by several factors (Nergaard and Grimholt 2010).

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.