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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.
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 x 10(6) bbl [64 x 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.
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 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 17 in. [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.
Most gravel packed completions are considered successful if the well produces sand free. However, many successfully gravel packed wells suffer reduced productivity as a result of formation damage induced by current gravel pack completion practices. Gravel packing even a slightly damaged formation can result in long term detrimental effects on production. The most predominate problem is that dehydration of the gravel carrier fluid will be restricted and perforation tunnels will not tightly pack.
The areas of interest in which formation damage can be limited during a gravel pack completion include perforating, filtration, gravel carrier fluid selection, lost circulation control, and workstring hygiene. In addition, fluid leak-off during gravel packing may be optimized by proceeding the gravel pack slurry with low strength acid.
Optimization of gravel placement during completion operations has been a widely discussed subject in recent years. The predominate objective has been to perform a gravel pack which results in little of no draw-down across the perforations. Numerous operators choose the position of attempting as clean a completion as possible; then, evaluate the well's performance following completion to determine weather or not a stimulation treatment required. An important observation of this practice is discussed by McLeod. If a well experiences excessive pressure draw-down following completion, the perforation tunnels may not adequately pack-off during gravel packing. Injecting acid into such a completion may result in creating or expanding existing tunnel voids and pack voids in the screen-casing annulus. The production decline following such a completion is often attributed to fines migration when in fact we have at least a partially failed gravel pack.
The objective of gravel packing should be to eliminate all of the possible mechanisms which may lead to pressure draw-down prior to achieving a sand out. As an industry, we have made great strides in recent years to improve our performance in gravel packed completions. However, there exist areas which require clarification in order to further reduce formation damage during gravel packing.
The benefits derived from optimized filtration practices for completion, workover and stimulation fluids has been extensively documented. In most cases, the formation damage caused by dirty fluids can never be completely removed. Therefore, damage prevention should be the paramount consideration. Achieving optimum damage prevention while maintaining cost control objectives requires a broad knowledge of filtration theory as well as the best demonstrated field practice.
Filtration theory states that fluid clarity guidelines can be achieved by adjusting either flow rate or surface area. In the case of high fluid densities and/or viscosities, as are encountered during a workover, filtration may be controlled by: 1) reducing flow rate, 2) increasing the filter surface area, and 3) a combination of flow rate and surface area. The level of filtration depends on reservoir plugging potential, practical limitations of filtration devices, physical properties of the influent, and cost.
Distinguished Author Series articles are general, descriptiverepresentations that summarize the state of the art in an area of technology bydescribing recent developments for readers who are not specialists in thetopics 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 petroleumengineering.
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 thatformation 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.
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 formationcondition near the wellbore. Although the drainage radius may be severalhundreds of feet, the effective permeability close to the wellbore has adisproportionate effect on well productivity.
This paper was prepared for presentation at the 1999 SPE Asia Pacific Oil and Gas Conference and Exhibition held in Jakarta, Indonesia, 20–22 April 1999.