In the early stages of real-time data transmission from the rigsite, real-time monitoring engineers focused on viewing data as it was presented on the rigsite. While this setup was ideal for service quality and event mitigation, it fell short of providing predictions of wellbore condition. As remote real-time monitoring matures in its use of "while drilling" data, remote engineers need to identify issues before they affect drilling operations and are evident to rigsite personnel. Using a combination of data analysis, engineering models, algorithms for data reduction, historic behavior, and experience, a remote monitoring engineer is able to see the data in the context of the drilling environment and to identify developing incidents. However, as data volume increases, remote engineers must focus their analysis on the tools by which they can have the biggest impact and effectiveness. Real-time hydraulics and torque and drag (T&D) analysis are such tools, and by using engineering models, engineers can judge the condition of a wellbore before it impacts operations. Two examples show how effective monitoring of "while drilling" models of hydraulics and T&D identified events, allowing them to be prevented before they were evident on the rigsite and caused nonproductive time.

TX 75083-3836 U.S.A., fax 01-972-952-9435. AbstractA successful reservoir flood depends on a properly designed injection/production pattern. Knowledge of the flow pattern within a reservoir leads to a better design of the injection pattern, which in turn enhances overall recovery. To achieve this goal an interwell tracer program was used to characterize the flow stream within the current injection/production pattern of the central part of the Mesozoic Chiapas-Tapasco Basin. The field includes one injector and four producers. Due to production, the average reservoir pressure fell and approached the dew point at reservoir conditions. Natural gas was injected to maintain reservoir pressure and optimize condensate production. A chemical interwell tracer was also injected to detect and evaluate the magnitude of any communication between the injection and production wells and to track the areal flow pattern within the field. The study was designed for 18 months and commenced in December 2000. The results from the sample analyses provided information on the magnitude of highly permeable channels between the injector and producers as well as flow pattern within the field. Furthermore, the results provided valuable information on breakthrough time, which in turn shall lead to a more efficient gas injection design.

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.

No abstract

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 fractured production channels and initiating 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 located in southern Mexico that have been producing since 1995, an operator needed to determine where the asphaltene precipitation was occurring. An integrated diagnosis workflow that included the creation and analysis of the asphaltene phase envelope plus an asphaltene-onset screening test using a solids-detection system (SDS) was instrumented.After coupling screening results with a pressure-temperature flowing survey, it was identified that asphaltene precipitation occurred inside the reservoir when the bottom-hole 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 workflow; this methodology includes a new adsorptiontype asphaltene inhibitor as part of the matrix cleanup treatment. As a result of this diagnostic-solution workflow, 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 flowrates plus significant reduction in well intervention and deferred production costs. Additionally, the post-treatment results showed that in 50% of the documented interventions, the inhibitor treatment improved overall production performance by at least 10%.