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Conventional well completions in soft formations (the compressive strength is less than 1,000 psi) commonly produce formation sand or fines with fluids. These formations are usually geologically young (Tertiary age) and shallow, and they have little or no natural cementation. Sand production is unwanted because it can plug wells, erode equipment, and reduce well productivity. It also has no economic value. Nonetheless, formation sand production from wells is dealt with daily on a global basis. In certain producing regions, sand control completions are the dominant type and result in considerable added expense to operations.
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- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.46)
- North America > United States > California > Sacramento Basin > 4 Formation (0.99)
- North America > United States > California > Sacramento Basin > 3 Formation (0.99)
- North America > United States > California > Sacramento Basin > 2 Formation (0.99)
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W.L. Penberthy Jr. (retired, Exxon Production Research Co.), with contributions from Baker Oil Tools Conventional well completions in soft formations (the compressive strength is less than 1,000 psi) commonly produce formation sand or fines with fluids. These formations are usually geologically young (Tertiary age) and shallow, and they have little or no natural cementation. Sand production is unwanted because it can plug wells, erode equipment, and reduce well productivity. It also has no economic value. Nonetheless, formation sand production from wells is dealt with daily on a global basis. In certain producing regions, sand control completions are the dominant type and result in considerable added expense to operations. Fluid flow from wells is the consequence of the wellbore pressure being smaller than that in the reservoir. The drag force caused by the flow from large to small pressure is related to the velocity-viscosity product at any point around the well.
- North America > United States (0.46)
- Europe > Norway > Norwegian Sea (0.25)
- Geology > Mineral (0.93)
- Geology > Geological Subdiscipline > Geomechanics (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.67)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.99)
- Information Technology > Knowledge Management (0.40)
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Summary. Sarawak Shell Bhd./Sabah Shell Petroleum Co. (SSB/SSPC) experience with gravel-packed completions covers some 12 years. During that period, some 290 gravel-packed zones have been completed, and about 400 ร 10(6) bbl [64 ร 10(6) m3] of oil have been produced through gravel packs in 13 offshore fields, This paper presents an overview of the development of gravel-packing methods, with special reference to the new gravel-packing technique developed in early 1984 for the Bayan field gravel-packed completions. Productivity reduction resulting from gravel packing and the long-term performance of the packs are discussed briefly. Introduction SSB and SSPC jointly operate some 16 offshore oil fields under two production-sharing contracts with Petronas, the Malaysian Natl. Oil Corp. All fields are located offshore in the east Malaysian states of Sarawak and Sabah. Fig. 1 is a situation map showing the various SSB/SSPC fields. For operational and logistical reasons, the crude oil from these fields is produced to one of the three crude oil terminals located at Bintulu, Lutong, and Labuan. The shallow, friable, and relatively unconsolidated formations in most of these fields require implementation of a sand-exclusion technique. Installation of inside-casing gravel packs (IGP's) followed by slurry placement of gravel remains the most widely used method in the area over the last decade. Gravel-packed intervals ranging from 10 to 650 ft [3 to 198 m] have been completed successfully with gravel packing. Most packs have been installed inside perforated casing. With extensive field experience acquired over the years and from detailed analytical data obtained from ongoing field completion reviews, we have further developed and improved the technique for gravel-packed completions. Since 1984, a new procedure has been formulated and applied in three fields. Sand-Exclusion Requirements/Methods Sand-Exclusion Criteria. As yet, no rigorous mathematical approach is available for the prediction of sand production tendencies. However, some empirical relationships (e.g., sonic transit time and total drawdowns) have been derived through extensive in-house studies conducted for the North West Borneo fields (South West Ampa field in Brunei, in particular). These data are currently being used as guidelines for sand-exclusion requirements. In the North West Borneo fields, a sonic transit time of 90 sec/ft [295 s/m] has commonly been used as a cutoff criterion for sand exclusion. Wherever possible, rock failure strengths and Brinell hardness measurements on reservoir core samples are also used to supplement the petrophysical data. Other considerations include sand-failure test results obtained during production tests, formation permeability, and porosity. Fig. 2 summarizes the typical depths in SSB/SSPC fields where sand-exclusion methods have been applied. Sand-Exclusion Methods. Gravel packing has been the only method of sand exclusion used in SSB/SSPC projects. Two gravel-pack installation techniques have been used: underreamed openhole (OHGP) and IGP'S. Underreamed OHGPS. This method was applied in the earlier Tukau and Samarang wells for both single- and dual-zone completions. Fig. 3 depicts a typical downhole gravel-pack configuration for both single- and dual-zone completions. For a single-zone OHGP, the 9 5/8-in. [24.4-cm] casing was cemented above the pay zone. After the well was drilled to total depth (TD), the pay zone was underreamed to 15 in. [38 cm], with starch brine as the underreaming fluid. A four-arm caliper tool was then run to verify the dimensions of the underreamed section, hence allowing an estimate of the gravel volume required. After the 7-in. [18-cm] slotted liner assembly was run, the liner hanger packer was set and tested to 200 psig [1380 kpa] from below through the gravel-packing port collar. Gravel packing was carried out with starch brine as the carrier fluid at gravel concentrations of 0.2 to 0.4 lbm/gal [24 to 48 kg/m3]. The gravel was placed outside the slotted liner through the port collar with a combination tool. Surface pump pressures and rates varied but averaged 100 to 200 psig [690 to 1380 kPa] at 2 to 4 bbl/min [0.005 to 0.01 m3/s], respectively. After a screenout was observed, the liner slots were washed with brine treated with an enzyme (bactamyl or maxamyl) to facilitate the break-down of the starch. Repackings used the enzyme brine as the carrier fluid, when necessary. In a dual-zone OHGP, a 12 -in. [31.1-cm] hole was drilled to TD and the pay zones were underreamed to 17in. [44 cm] with (clean) starch brine. A four-arm caliper tool was then run to verify the dimensions of the underreamed intervals and to estimate gravel requirement. SPEPE P. 81^
- Asia > Brunei (0.88)
- North America > United States > Wyoming > Campbell County (0.24)
- Asia > Malaysia > Sabah > South China Sea > Sabah Basin > Block SB301 > Samarang Field (0.99)
- Asia > Brunei > South West Ampa Field (0.99)
- Asia > Malaysia > Sarawak > South China Sea > Sarawak Basin > Baram Delta Province > Tukau Field (0.94)
Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and presentspecific details only to illustrate the technology. Purpose: to informthe general readership of recent advances in various areas of petroleum engineering. Summary Almost every field operation is a potential source of damage towell productivity. This paper provides a broad overview of the nature offormation damage problems, how they occur during various oilfield operations, and their effects on well productivity. Diagnosis of formation damage problems has led to the conclusion that formation damage is usually associated with either the movement and bridging offine solids or chemical reactions and thermodynamic considerations. The finesolids may be introduced from wellbore fluids or generated in situ by theinteraction of invading fluids with rock minerals or formation fluids. Control of formation damage requires proper design of treating fluids forchemical compatability and strict quality control of fluid physical andchemical properties during treatment. The use of treating fluid filtration, clean work strings (pipe), and inhibited fluids has been shown to be importantin the control of formation damage during well treatment. Introduction Laboratory and field studies indicate that almost every operation in thefield--drilling, completion, workover, production, and stimulation--is apotential source of damage to well productivity. During the many years when thecost of oil was extremely low, however, productivity damage was largely ignoredand emphasis was placed on minimizing costs rather than maximizingproductivity. Since the advent of the energy crisis and the Arab embargo, prevention of formation damage and maximization of well productivity has takenon added importance, not only for conventional well operations but also fortaking advantage of EOR. In EOR, if the conductivity of injection and producingwells is damaged, sweep efficiencies and recovery factors will be adverselyaffected. The success or failure of an EOR project may depend on the ability toinject planned amounts of special fluids and to produce oil at adequaterates. Because repair of formation damage is usually difficult and costly, thebasic approach should be to prevent damage. To achieve this goal, the entireprocess of drilling, completion, and production needs to be viewed as a whole, including extensive preplanning, execution, and follow-up. Failure to controltreatment or operating procedures and chemicals properly at any stage maynegate the effectiveness of all other well-designed and -executed operations. Severely damaged productivity may result from a single misstep in the path ofwell development. A broad knowledge of how formation damage occurs is the first step inprevention of well damage. Each operation must then be studied in detail. Thispaper takes the first step by reviewing how formation damage occurs and showinghow it affects well productivity in various operations. Relative Importance of Formation Damage First, let us look briefly at the relative importance of the formation condition near the wellbore. Although the drainage radius may be several hundreds of feet, the effective permeability close to the wellbore has adisproportionate effect on well productivity. JPT P. 131^
- Geology > Mineral > Silicate (0.69)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.48)
- North America > United States > California > Los Angeles Basin (0.99)
- South America > Brazil > Parnaiba Basin > Block PN-T-68 > California Field (0.97)
Krueger, R.F., KGK Petroleum Consultants SPE Member Abstract Almost every field operation is a potential source of damage to well productivity. This paper provides a broad overview of the nature of formation damage problems, how they occur during various oilfield operations, and their effects on well productivity. Diagnosis of numerous formation damage problems has led to the conclusion that formation damage is usually associated with either the movement and bridging of fine solids or chemical reactions and thermodynamic considerations. The fine solids may be introduced from wellbore fluids or generated in situ by the interaction of invading fluids with rock minerals or formation fluids. Control of formation damage requires proper design of treating fluids for chemical compatibility and strict quality control of fluid physical and chemical properties during treatment. The use of treating fluid filtration, clean work strings (pipe), and inhibited fluids has been shown to be important in the control of formation damage during well treatment. Introduction Laboratory and field studies indicate that almost every operation in the field - drilling, completion, workover, production, and stimulation - is a potential source of damage to well productivity. During the many years when the cost of oil was extremely low, however, productivity damage was largely ignored arid emphasis was placed on minimizing costs rather than maximizing productivity. Since the advent of the energy crisis and the Arab embargo, prevention of formation damage and maximization of well productivity has taken on added importance, not only for conventional well operations but also for taking advantage of EOR. In EOR, if the conductivity of injection and producing wells is damaged, sweep efficiencies and recovery factors will be adversely affected. The success or failure of an EOR project may depend on the ability to produce oil at adequate rates. Because repair of formation damage is usually difficult and costly, the basic approach should be to prevent damage. To achieve this goal, the entire process of drilling, completion, and production needs to be viewed as a whole, including extensive pre-planning, execution, and follow-up. Failure to control treatment or operating procedures and chemicals properly at any stage may negate the effectiveness of all other well-designed and executed operations. Severely damaged productivity may result from a single misstep in the path of well development. A broad knowledge of how formation damage occurs is the first step in prevention of well damage. Each operation must then be studied in detail. This paper takes the first step by reviewing how formation damage occurs and showing how it affects well productivity in various operations. RELATIVE IMPORTANCE OF FORMATION DAMAGE First, let us look briefly at the relative importance of the formation condition near the wellbore. Although the drainage radius may be several hundreds of feet, the effective permeability close to the wellbore has a disproportionate effect on well productivity. This problem is illustrated in Fig. I for a well located in an inner concentric zone of different permeability from the surrounding formation. In this illustration, the normalized well productivity is plotted vs. the normalized permeability in a radial system. The normalized values represent the value of the variable in the inner concentric zone divided by the value of the same variable in the main surrounding formation. P. 535^
- Geology > Mineral (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.47)
- North America > United States > California > Santa Barbara Basin > Cat Canyon Field (0.99)
- South America > Brazil > Parnaiba Basin > Block PN-T-68 > California Field (0.97)