Summary The natural state of asphaltenes in petroleum fluids is described as a colloidal system stabilized, to some extent, by the resins that act as peptizing agents. Destabilization of colloidal asphaltenes appears to happen as a result of changes in temperature, pressure, and composition. This can significantly affect the production efficiency of a reservoir during oil recovery. The phenomenon of asphaltene flocculation and deposition in well tubing appears to be influenced by two mechanisms: the fluid-phase (gas/liquid/solid) separation and the well-flow regime. Predictions of the onset of asphaltene flocculation determined by fluid-phase laboratory studies do not necessarily imply that asphaltene deposition will occur during flow conditions. This paper presents a method for predicting the onset of asphaltene deposition under well-flow conditions. This method will allow us to take preventive actions before asphaltenes problems occur by keeping the asphaltenes dispersed in the oil phase. A well-monitoring technique was used in west Kuwait Marrat (Jurassic) deep wells to monitor the well-flow pressure by use of a programmable data logger. The data gathered from the logger predicted the onset of the flow-regime mechanism that influenced asphaltene deposition in well tubing. The deposition thickness of asphaltenes in well tubing was estimated by the data and was found to agree with the results obtained by the caliper test. Introduction It is generally1-6 accepted that crude oil is considered to be a colloidal system comprising fractions of saturates, asphaltenes, resins, and aromatics. Asphaltene fractions are defined as dispersed colloids in the oil phase and are stabilized, to some extent, by the resin molecules that act as protective bodies for asphaltene particles. Colloidal asphaltenes can be naturally or artificially precipitated if the resins' protective shield is removed from asphaltene-particle surfaces. The details of asphaltene characterization have been reported in numerous studies. Asphaltene deposition can occur in different parts of the production system, including in the well tubing, the surface flowlines, and even the nea- wellbore reservoir. Asphaltene precipitation and deposition in oil-production systems depend on the changes in flow conditions, such as pressure, temperature, and oil composition.7–11 The factor that plays a major role in asphaltene problems under flow conditions is well-flow pressure behavior. This pressure controls the well-flow regime within the production system. In tubing, as the well fluid moves vertically, flow-regime changes take place, complicating the multiphase flow, which may cause severe asphaltene flocculation and deposition. This phenomenon can decrease well and, potentially, reservoir productivity, as well as increase production costs by requiring frequent chemical treatments for the removal of asphaltenes. In the Arabian Gulf, it has been observed that asphaltene-deposition problems in well tubing have increased in recent years.12 This may be because of changes in reservoir pressure with time and the increased gas/oil ratio (GOR). The latter has been shown to be an important factor in asphaltene-particle flocculation in production systems. In west Kuwait, asphaltene depositions in well tubings have been increasing in deep wells.12 This paper focuses on the monitoring of asphaltene flocculation and deposition in oilwell tubing. The monitoring technique is based on the interpretation of the flowing-wellhead-pressure data obtained from a programmable data logger.

This paper presents the methodology to identify critically stressed fractures, CSF, in naturally fractured reservoirs. A natural fracture is considered to be critically stressed if the ratio of shear and normal stresses acting on the fracture surface exceeds the frictional strength of the reservoir rock. The main objective is to identify the critically stressed fracture trends in the reservoirs in order to design wellbore trajectories that efficiently intersect theses fracture trends. In addition, geomechanical analysis for drilling scenarios under depleting reservoir conditions addressing well-bore stability is attempted to formulate drilling and completion strategy. Critically stressed fracture identification has several important implications on fluid flow behavior through naturally fractured porous media. It has been shown that fluid flow in fractured rocks is largely controlled by critically stressed fractures; therefore, critically stressed fracture analysis may enable to systematically identify producing fractures in the reservoirs that mainly produce through natural fractures. The CSF analysis includes the mechanical property characterization of the formations and the in-situ stress tensor description acting on the reservoirs. The fracture orientations from core description & borehole image log interpretation were used for the CSF analysis because fracture dip and strike are needed for the stress calculation on fracture planes. This analysis is particularly useful where several fracture trends are identified in a reservoir, with some trends more likely to be open and productive due to horizontal stress anisotropy. The case history illustrates application of CSF Analysis in conjunction with geomechanical wellbore stability analysis in selection of optimal well trajectory and formulation of drilling and completion strategy for producing a naturally fractured carbonate reservoir. Introduction This paper presents a case study involving comprehensive geomechanical characerisation of a Fractured Najma-Sargelu (NJ-SR) reservoir in an oilfield of West Kuwait (Fig.1) with special emphasis on critically stressed fracture analysis. The work includes rock mechanical characterization, in-situ stress tensor analysis, critically-stressed fracture identification as well as well bore stability analysis for drilling scenarios under depleting reservoir conditions. The overall objective of this work is to provide results that can be practically used in the field to ensure proper well planning and drilling practices, as well as for the selection of suitable drilling and completion strategies for production. Analysis Methodology and Results Static Mechanical Properties Static mechanical properties are the fundamental inputs for in-situ stress estimation, critical drawdown pressure calculation, fracturing tendency analysis, borehole stability analysis and mud weight window designs. These properties are traditionally obtained by conducting triaxial compression test in the laboratory; however, such measurements are routinely not carried out due to expense and/or limited availability of core material. Therefore, an analytical program was used to derive static mechanical properties from well log data and formation petrophysical description. The program is based on FORMEL, a constitutive model describing the microscopic processes occurring in a rock sample during mechanical loading.1 The program provides continuous representation of the formation's mechanical properties with depth, which is the ultimate objective in geomechanical characterization. Well logging and laboratory data from five offset wells (#B, #E, #F, #G and #H-1) were utilized to determine the static rock mechanical properties of the lithological column, covering NJ-SR formations. At the depth of interest (>10,000 ft), this formation in the field may be classified as moderate to high strength, as the average UCS (unconfined compressive strength) values for these rocks were found to be in excess of 6,000 psi. The log derived rock strength was corroborated with laboratory test data on a core samples from one well (#B) in NJ-SR formations.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractNajmah-Sargelu (NJ-SR) unconventional fractured carbonate and Middle Marrat (MMR) tight carbonate Jurassic reservoirs are spread across many fields in West Kuwait where new Jurassic oilfields are still being discovered. Oil is being produced since late eighties mainly from MN, UG, AB and DF structures. Drilling through over pressured and fractured NJ-SR reservoir, lying below thick high pressure Gotnia Evaporites is challenging due to well control issues such as total mud losses and kicks compounded with high H 2 S-high CO 2 corrosive environment. Moreover, pressure reversal in MMR and depleted pressures pose further complications resulting in costly wells.

The development of light-oil reservoirs in Kuwait has become increasingly more important for maintaining the quality of exported crude. This is due to the fact that producing light-oil reservoirs has proven to be not only a necessary link for maintaining the oil production from this area but also for increasing it. As a result, efficient testing of the light-oil reservoirs has become paramount in importance for overall well and field development. The reservoirs in Kuwait are low permeability, high pressure/high temperature (HP/HT) and sour. In earlier wells, the strategy had been to perforate these formations balanced or slightly overbalanced, in mud, with through-tubing guns. Results from testing in several wells indicated that if they could be perforated under-balanced, the formations would yield better results since this method would allow better penetration and perforation cleanup. A number of reservoirs are stacked horizontally and range from typically conventional to fractured limestone. In view of the corrosive nature of the fluids present, one of the primary efforts in the testing of these wells had to be directed toward keeping the number of wireline and coiled-tubing operations to a minimum without compromising the testing objectives. Since it was necessary to test multiple objects in the exploratory wells individually, special effort was focused on determining methods that could effect a reduction in the testing period for each object. By reducing individual testing times, Kuwait Oil Company felt that the overall savings would be significant. Several areas were identified that would require special consideration. This paper will discuss these areas (listed below) and how the challenges they presented were addressed:Modifications to retrievable completion test (RCT) tools and tubing-conveyed perforating (TCP) equipment that would be required to test these zones efficiently.The challenges associated with designing and carrying out the tests.Ongoing modifications in the testing methodology to overcome the testing challenges.The operation of the test-string, annulus-pressure-responsive components in the heavy oil-based mud and the difficult wellbore conditions.How the problems of shaped charge performance in the naturally fractured formations with unusually high compressive strength and very low matrix permeability and porosity were resolved. The modifications to tools and methods allowed the goals of the operator and service provider to be met. Background Fig. 1 shows a typical completion schematic for the formations intercepted in the deep Jurassic layers of west Kuwait. Monobore completions are normally used. The reservoir evaluation technique followed by the Kuwait Oil Company in the wells of west Kuwait follows:Drill and complete well in the zone of interestMobilize and rig-up wireline perforation unit and production testing spreadPerforate the well using through-tubing guns with mud capsFlowtest the well through the production testing unit on location. While the above procedures were satisfactory, it was felt that that better well performance and completion efficiency could be achieved by a step change in the formation evaluating technique. Other options were reviewed.1,2,3 The first change planned was to test the well using a retrievable completion test (RCT) string. The reasons for making this change were due to the testing methodology adopted and the changes made to the procedural operations. These changes follow:Since the wells were deep with a telescopic casing design, and the reservoir was sour, the decision was made to test using completion tubing instead of the drill string.A Christmas tree was to be used as opposed to a surface test tree with testing performed through the blowout preventers (BOPs) as in a regular test. Safety was the primary driver for using a Christmas tree as the well had H2S and high pressures.

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