Asphaltene deposition in the reservoir, wellbore and facilities has long been recognized as a problem in the Marrat reservoir in the Magwa field, Kuwait. One option of avoiding asphaltene problems in the reservoir, including the near wellbore region, is to maintain reservoir pressure and flowing BHPs above the asphaltene onset pressure (AOP). Given that there is a large pressure difference between AOP and the bubble point pressure and that natural flow is possible at pressure well below AOP, there may be economic benefits in operating the reservoir at pressures below AOP. Benefits relate the reduced and delayed costs of water injection facilities. There may also be some additional recovery related to fluid expansion. Potential problems relate to possible adverse changes to relative permeability due to asphaltene related wettability changes, productivity impairment due to near well-bore asphaltene deposition and increased asphaltene problems in the wellbore. The second and third of these potential problems have been assessed by a field trial. This paper describes the selection of a candidate well and the design of a field trial to assess these problems. The selected well was produced first with FBHP well above the AOP. Asphaltene deposition in the tubing was monitored, fluid samples were taken and pressure transient tests were performed to diagnose well inflow performance. No decline in well productivity was seen in this period. Asphaltene deposition in the tubing was a problem and the well required cleaning during this period. The well was then produced at high rate, with flowing BHP well below AOP and a similar surveillance program was carried out. Finally the well was returned to low rate production. Analysis of the data from the high rate and subsequent low rate production periods indicated that there had been a limited decrease in well productivity. These data also showed that asphaltene deposition in the tubing was less of a problem during the high rate test than during the preceding low rate test.

The Magwa Marrat reservoir was discovered in the mid-1980s and has been produced to date under primary depletion. Reservoir pressure has declined and is approaching the asphaltene onset pressure (AOP). A water flood is being planned and a decision needs to be taken as to the appropriate reservoir operating pressure. In particular the merits of operating the reservoir at pressures above and below the AOP need to be assessed. Some of the issues related to this decision relate to the effects of asphaltene deposition in the reservoir. Two effects have been evaluated. Firstly the effect of in-situ deposition of asphaltene on wettability and the influence that this may have on water-flood recovery has been investigated using pore scale network modes. Models were constructed and calibrated to available high pressure mercury capillary pressure data and to relative permeability data from reservoir condition core floods. The changes to relative permeability characteristics that would result from the reservoir becoming substantially more oil-wet have been evaluated. Based on this there seems to be a very limited scope for poorer water flood performance at pressures below AOP. Secondly the scope for impaired well performance has been evaluated. This has been done using a field trial where a well was produced at pressures above and substantially below AOP and pressure transient data were used to estimate near wellbore damage "skin". Also compositional simulation has been used to estimate near wellbore deposition effects. This has involved developing an equation of state model and identifying, using computer assisted history matching, a range of parameters that could be consistent with core flood experiments of asphaltene deposition. Results of simulation using these parameters are compared with field observation and used to predict the range of possible future well productivity decline. Overall this work allows an evaluation of the preferred operating pressure, which can drop below the AOP, resulting in lower operating costs and higher final recovery without substantial impairment to either water-flood efficiency or well productivity.

The Mauddud Formation in the Greater Burgan field is a thin carbonate reservoir with very low permeability but with moderate to good porosity and variable fracture density. The formation could be divided into three distinctive layers, based on the structural and digenetic complexities. Production in Mauddud wells show rapid decline due to tight rock matrix (low permeability). This decline is associated with an increase in Gas-Oil Ratio (GOR) as reservoir pressure falls below the bubble point pressure near the wellbore. Horizontal wells were drilled in an attempt to develop the Mauddud Formation targeting sweet zone. Most of the wells were located in a relative structural high on the up-thrown blocks of the North and Eastern flank of the Greater Burgan field that had the highest likelihood of intersecting fractures. They are mostly adjoining the major faults. There are now around 40 wells drilled in Mauddud including horizontal and multilaterals, most of which became non-producers due to above reasons. A study has been carried out to evaluate opportunities to revive these wells through available and new technologies in the industry. A detailed geological study incorporating all the available data was carried out initially. Wells were screened for stimulation by using various proven new technologies. Acid Frac, Stage Frac, near well bore SurgiFrac and Matrix Acid techniques have been applied with varying results. Advanced placement technique like distributed temperature profiling was used in some of the jobs. This paper presents the details of the application of the above mentioned technologies, to the candidate wells and discusses the results. The success of some of these technologies opened up new opportunities for a new beginning to revive the closed wells completed in Mauddud Formation.

A pilot water flood was carried out in the Marrat reservoir in the Magwa Field. The main aim of this pilot was to allow an assessment of the ability to sustain injection, better understand reservoir characteristics. A sector model was built to help with this task.An evaluation of the injectivity in Magwa Marrat reservoir was performed with particular attention to studying how injectivity varied as injected water quality was changed. This was done using modified Hall Plots, injection logs, flow logs and time lapse temperature logs.Data acquisition during the course of the pilot was used to better understand reservoir heterogeneity. This included the acquisition of pressure transient and interference data, multiple production and injection logs, temperature logging, monitoring production water chemistry, the use of tracers and a re-evaluation of the log and core data to better understand to role of fractures.A geological model using detailed reservoir characterization and a 3D discrete fracture network model was constructed. Fracture corridors were derived from fractured lineaments interpreted from different seismic attribute maps:A sector model of the pilot flood area was then derived and used to integrate the results of the surveillance data. The main output is to develop an understanding of the natural fracture system occurring in the different units of the Marrat reservoir and to characterize their organization and distribution. The lessons learned from this sector modeling work will then be integrated in the Marrat full field study.The work described here shows how pilot water flood results can be used to reduce risk related to both injectivity and to reservoir heterogeneity in the secondary development of a major reservoir.

Cement pulsation is a novel technology for enhancing zonal isolation by applying low frequency, hydraulic, pressure pulses to the wellhead immediately after cementing. The treatment maintains the slurry in a liquid state, which transmits hydrostatic pressure downhole, and keeps the well overbalanced thus preventing early gas flow after cementing. The paper summarizes several stages in the development of cement pulsation technology including comparison to other methods, physical principles, process analysis, mathematical modeling, computer-aided design, laboratory testing, and field performance. The paper supports published information on cement pulsation with data from research and field studies that was instrumental in developing the technology. Emphasis has been given to the analysis of the pulsation process, description of design model and software, and an updated account of field applications. Described is the MS Windows software for pulsation design. Two examples demonstrate the computer-aided design. The examples show that the software could be used to find the pulse size and treatment duration for a constant-pressure treatment. Alternatively, a variable-pressure treatment with controlled treatment depth could be designed. Data is presented from pulsation of over 80 wells in drilling areas notorious for early gas migration after cementing. Field applications of the technology in 80 wells provided significant evidence of the success of cement pulsation in preventing early gas leakeage in cemented wells. Introduction - Top Cement Pulsation In 1982, a landmark field experiment performed by Exxon revealed hydrostatic pressure loss in the annuli after primary cementing in wells1. Since then, hydrostatic pressure loss after cement placement has been considered a primary reason for gas migration outside wells. As the annular cement - still in liquid state - loses hydrostatic pressure, the well becomes under-balanced and formation gas invades the slurry and finds its way upwards resulting in the loss of well's integrity. Cement slurry vibration using a low-frequency cyclic pulsation is used by the construction industry for improving quality of cement in terms of better compaction, compressive strength, and fill-up. (Cement gelation or transmission of hydrostatic pressure is not a concern in these applications.) In the oil industry, the idea of keeping cement slurry in motion after placement has been postulated a promising method for prolonging slurry fluidity in order to sustain hydrostatic pressure and prevent entry of gas into the well's annulus. The idea was based upon experimental observations that cement slurries in continuous motion remained liquidous for a prolonged period of time2,3. Manipulating the casing string would move the cement slurry. Thus, early concepts considered keeping cement slurry in motion through casing rotation or reciprocation4,5,6. The motion should improve displacement of drilling mud and placement of cement slurry in the annulus. The use of forced casing vibrations for gas flow control has become subject of several inventions in the 80's and 90's7,8,9,10,11,12. For example, "enhanced filling of annulus with cement slurry without rotating or reciprocating the casing" was considered the main advantage of the first casing vibration method with mechanical vibrator placed at the bottom of the casing string7. All these methods have been already experimentally studied and patented. However, none of them have been used commercially because of difficulty involved in manipulating the entire casing string. Apparently, heavy equipment and installatioin needed to vibrate a long and heavy string of casing makes these methods not feasible, even onshore.