TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe fractured Monterey formation of offshore California is estimated by the MMS to contain over one billion barrels of remaining reserves. Quantitative wireline evaluation in fractured reservoirs had been difficult in the past. Resistivity imaging using the FMI tool now provides the clarity to identify, orient, and quantify individual fractures. And recently, with the addition of the Modular Formation Dynamics Tester (MDT) tool, the fluid content of selected fractures can be positively identified while the tool is downhole. In addition, transient pressure analysis can be performed to reveal critical reservoir parameters. On a series of offshore Monterey wells, the FMI and MDT were used to identify and test fractures. The MDT was configured with the Dual Packer module in order to straddle-test fractured intervals selected from the FMI image. Tests were conducted to identify the fluid contained in the fractures, locate the reservoir gas cap, acquire pressure data, and take fluid samples. Perforations were confidently selected in the zones with the best quality fractures to maximize oil and to minimize gas production. Analysis of the buildup data provided formation pressure, permeability, and skin damage information. Comparisons of the fracture permeability with the corresponding resistivity image gave a visual calibration for enhanced image interpretation. Analysis of the formation pressures also provided an understanding of the hydraulic communication between different layers within the Monterey.
Production from naturally fractured reservoirs can be greatly enhanced by stimulation with acid. When pumping the treatment from the surface (a bullhead treatment), the acid tends to enter the reservoir at the most permeable interval (conductive natural fractures). Without any other injectivity control, the acid will not likely divert from this path. Mechanical diversion techniques using swab cups or inflatable packers on jointed pipe or coiled tubing (CT) can ensure injection into the various intervals.With these methods, surface pressure can be monitored to assess fluid placement effectiveness for each zone treated, but uncertainty of the friction pressure in the pipe while pumping can result in an incorrect interpretation of fluid entry. These mechanical isolation techniques are typically more costly and time consuming than bullhead jobs. Diversion techniques for bullhead stimulation treatments using chemical or foam diverters are more efficient, but lack the confirmation that all the zones received acid because of uncertainty of interpreting downhole behavior from surface pressure. A new technique using fiber-optic distributed temperature sensing (DTS) measurements offers a solution when bullheading by providing an indication of where the acid has been injected into the fractured reservoir.A system has been developed consisting of a fiber-optic element encased in an acid-resistant slickline (commonly referred to as SL-DTS) that can be deployed in wells to monitor acid treatments in real time. The entire length of the fiber-optic strand functions as a temperature sensor with a vertical resolution of approximately 3.5 ft. The SL-DTS is gravity deployed or can be pumped into highly deviated or horizontal wells prior to the stimulation treatment. Once in place, the fiber is interrogated with pulsed laser energy to record temperature profiles versus time over the entire fiber length. These time-based data allow easy observation of thermal events due to fluid injections as well as any exothermic reaction of the acid system with the formation. Surface-temperature fluid pumped into perforations provides a cooling effect along the flow path. Interaction of the acid system with carbonate-containing minerals in the formation generates heat. Temperature profiles observed during and after pumping can be used to detect and quantify the distribution of the fluid system into the various intervals.This method was used to successfully delineate acid placement in several deviated wells during bullhead stimulations. The data illustrate zones successfully treated as well as zones that may be targeted for remedial treatment. SL-DTS offers a unique opportunity to optimize stimulation placement in fractured reservoirs or any reservoir with variable injectivity.
Accurate production profiling in the fractured Monterey wells of offshore California is a challenging endeavor. Deviated wells, three-phase flow, and the unpredictable nature of production from natural fractures, makes possible almost any type of flow regime. New production logging sensors have been developed that use distributed probes to directly detect hydrocarbons and provide images of the flow profile. The FloView*, PSP, and GHOST* tools have been used in the Monterey to provide accurate profile data necessary for successful workover efforts. When these data are combined with fluid PVT data in flow modeling software, oil, gas, and water contributions from each perf interval are quantified. Based on this analysis, thru-tubing water shutoff workovers have been designed and successfully implemented in a number of Monterey wells. First hydrocarbon entry is clearly visible on the FloView field image, and the modeling software quantifies the reduction of water with the precise placement of a thru-tubing bridge plug. The caliper measurements included with the PSP provide enhanced spinner interpretation when casing ID changes unexpectedly. The distributed probes of the Ghost tool use optical refractance to positively identify gas in the borehole. With a clear picture of the situation, pinpoint accuracy can be applied when implementing the solution. In the Monterey, the results can be dramatic. Introduction The Miocene-age, Monterey formation of offshore California, has produced prolific quantities of oil and gas since the early 70's starting with Platform Holly. Twenty-nine of the 38 fields in the Pacific OCS, as well as a number of fields in State waters, have substantial reserves attributed to the Monterey Formation. The USGS estimates that as much as one billion barrels may yet to be discovered in the Monterey on undeveloped Federal leases offshore California. The Monterey is unusual in that it is both the source rock and the reservoir rock. Progressive diagenesis has converted the highly porous diatomite source rock into a highly fractured chert with essentially no effective primary porosity. Currently there are 10 platforms and more than 150 wells producing from fractured intervals in this formation. In addition, five of the producing Monterey fields have some sort of fluid injection for reservoir pressure maintenance. Recovery factors are generally very low. For example, cumulative Monterey production from Platform Holly is only 52 MMB from an original Oil-in-Place of 2.2 Billion barrels. Severely brecciated zones occur in close juxtaposition to reactivated normal faults and set up major pathways to the underlying aquifer. Rapid water movement up these vertical fracture paths severely impacts recovery per well. Reservoir monitoring and well maintenance planning require accurate fluid entry and flow profile data. Though-tubing production logs and subsequent use of this data in modeling software can provide this information.
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