Members SPE-AIME Abstract Pretreatment analysis, job planning, and well preparation lead to acidizing success in sandstones with permeabilities greater than 50 md. Formation mineral analysis improves success in sandstones with lower permeabilities. Injection pressure responses to acid injection provide data for onsite decisions. Introduction Many papers have been written about specific pro ducts for acidizing sandstone formations. Most often these products are designed to correct specific problems and are primarily based on laboratory research in sandstone cores. Very little has been written about evaluating problems that exist in oil and gas wells completed in sandstone formations. Identifying problems in real wells which can be solved with specific products is an important part of the overall acidizing program. This paper will attempt to provide insights into identifying problems and selecting the best product or process to remove the specific damage. Also, many papers have been written about specific acidizing design models. Most of these papers predict the spending of HF as it penetrates the formation and sometimes the permeability increase. These papers show that regular 3 percent HF only penetrates formations about 6-12 inches before the HF completely spends. More recent retarded HF acids have achieved deeper penetration. It has been the authors experience that the volume of acid predict by these models is not the real key to successful acidizing, but rather it is the control of injection into all the perforations in the formation that determines success. Moreover, some formations respond well to HF acids and others can be damaged by the application of either HF acid or HF acid. This paper will discuss the reasons for this with recommendation on which wells are potential HF acid successes and which wells should be stimulated in another way. PLANNING THE ACID TREATMENT The first step in planning an acidizing treatment is to determine whether the well is damaged and how much. One should determine the production potential of the well to see whether removing the damage will provide enough production increase to pay for the acid treatment in a reasonable period of time. The question to be asked in evaluating well damage are:when was the well damaged,how was it damaged, andwhat caused the damage. Production history curves often show when a well was damaged unless the damage occurred during drilling and completion. it is important for the engineer to understand all aspects of formation damage in order to interpret the records that exist in well files. Formation Damage Analysis Certain types of damage consistently occur in the three major phases of a well's life:drilling and cementing,completion andproduction. Information exists or can be obtained to show whether damage could have occurred and its mechanism. Drilling and Cementing Damage One of the most important sources of damage is that from drilling mud filtrates which usually have a high pH. Several authors, have shown that pH's above 11 are damaging to formations with significant quantities of clay, i.e. 5-20% by weight of clay. A recent paper, showed the variation of permeability with pH. This curve can be used as a first estimate to determine the reduction in permeability by invasion of formations with high pH mud filtrates.
The Bayu-Undan gas recycling project is located north of Australia, in the East Timor Sea and is designed to produce 1,100 MMscf/D of wet gas, strip out 110,000 B/D of condensate/LPG, initially reinject 950 MMscf/D of lean gas, and later export up to 700 MMscf/D of lean gas to a LNG plant in Darwin. The initial development called for 16 North Sea-style, 7 in. monobore wells (11 producers and 5 gas injectors). By May of 2003, it became apparent that the original well design would not achieve the 1.1 Bcf/D production target because of well construction problems. Three wells on the remotely located wellhead platform were abandoned because of wellbore instability. Without the production contribution from these wells, the first year's production target would not be met. To meet the production targets, a complete well redesign was undertaken. First, the tubing was upsized from 7 in. to 9–5/8 in. Then semi-openhole completions with pre-drilled liners and openhole packers were selected instead of the conventional cased and perforated design to reduce installation time. Finally, oil based drill-in fluid was selected to provide lubricity, temperature stability, and low liftoff pressure of the filter cake for rapid cleanup. Utilizing the Big Bore design, the production capacity of +1.1 Bcf/D and injection capacity of 1.1 Bcf/D was achieved in June of 2004, ahead of schedule. The well count was also reduced from 16 to 12 wells (8 producers and 4 gas injectors.) Two producers had capacities in excess of 300 MMscf/D, and three gas injectors had injection capacities in excess of 350 MMscf/D. The increased production resulted in 19 MMstb of condensate/LPGs produced in the first year, some 7–8 MMstb more than would otherwise have been the case. Introduction The Bayu-Undan Field is a retrograde gas-condensate field with a raw Gas-Initially-In-Place (GIIP) of 8–9 Tcf including 700 MMstb propane plus (C3+). The field is located in the Timor Sea and straddles the Joint Petroleum Development Area, JPDA. The Production Sharing Contracts, PSCs, 03–12 and 03–13 in the Timor Gap area are administered jointly by the countries of East Timor and Australia as seen in Figure 1. The Bayu-Undan gas recycling project was originally planned to be developed from two platforms, with eight - 7 in. monobore wells and eight - 7–5/8 in. monobore wells, consisting of 11 producers and five gas injectors. The planned well depths ranged from 4000 m (11,972 ft) to 6341 m (20,798 ft). This design would require well rates up to 220 MMscf/D, to meet the design premise of producing 1100 MMscf/D while re-injecting 950 MMscf/D of lean gas by July 2004. By 2006, when the LNG plant and pipeline were available, 475 MMscf/D would be transported to the LNG plant in Darwin and the remaining 475 MMscf/D of lean gas reinjected into the formation.1 The Bayu-Undan formation structure is a broad east-west trending horst with a number of culminations set up by internal eastwest and north-south trending faults as seen in Figure 2. The predominant hydrocarbon-bearing section of the Bayu-Undan Field occurs in the upper part of the Early to Middle Jurassic Plover Formation and throughout the Later Jurassic Elang Formation. In addition, a thin interval belonging to the Frigate and the Flamingo Formations forms a minor part of the pay zone, along the margins of the field. One distinct feature is a common gas-water-contact (GWC) interpreted across the field at 3109 mSS TVD (10,198 ft). Figure 3 presents a generalized stratigraphic column and reservoir characterization for Bayu-Undan.
Within the sand-control-technology sector today, there are many sand-exclusion screen options available for use in completion design. Sand-control screens have steadily improved with the introduction and enhancement of metal sand-retention-mediabased sand-exclusion products in the early 1990s. However, recent catastrophic sand-exclusion failures have led some operators and independent laboratories to perform additional testing and quality control checks on sand-exclusion products to ensure full life cycle field value.This paper describes a process to select sand-exclusion products by uniquely qualifying an individual product design, which includes retention media, metallurgy, subcomponents, manufacturing process, and the final assembled product. The technical evaluation is based on a two-tier qualification process that "uniquely qualifies" products for purchase consideration.Step 1 of the process tests the sand-retention media for plugging potential and solids retention.Step 2 then tests full-joint screens manufactured using media qualified during Step 1 for burst and collapse to ensure the product meets downhole performance specifications.Recent testing has illustrated a range of significant conclusions that the industry should be aware of:• Published screen burst and collapse ratings are not always equivalent to actual screen performance.• Burst and collapse pressures are not equivalent to basepipe rating.• Welds can vary by plant; therefore, screens may vary by manufacturing location.• Excessive drainage layer gap leads to premature burst or collapse failure.• Not adjusting screen design for changes in metallurgy may lead to premature failure.• Delamination has been observed in some sintered retention media.• Scaling a product design up or down without conducting a detailed engineering analysis may lead to premature failures.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractWithin the sand control technology sector today, there are many sand exclusion screen options available for use in completion design. Sand control screens have steadily improved with the introduction and enhancement of metal sand retention media based sand exclusion products in the early 1990's. However, recent catastrophic sand exclusion failures have led some operators and independent laboratories to perform additional testing and quality control checks on sand exclusion products to ensure full life cycle field value. This paper describes a process to select sand exclusion products by uniquely qualifying an individual product design which includes retention media, metallurgy, subcomponents, manufacturing process, and the final assembled product. The technical evaluation is based on a 2-tier qualification process that "uniquely qualifies" products for purchase consideration.Step 1 of the process tests the sand retention media for plugging potential and solids retention.Step 2 then tests fulljoint screens manufactured using media qualified during Step 1 for burst and collapse to ensure the product meets downhole performance specifications.Recent testing has illustrated a range of significant conclusions that the industry should be aware of:• Published screen burst and collapse ratings are not always equivalent to actual screen performance. • Burst and Collapse pressures are not equivalent to basepipe rating. • Welds can vary by plant; therefore screens may vary by manufacturing location. • Excessive drainage layer gap leads to premature burst or collapse failure.• Not adjusting screen design for changes in metallurgy may lead to premature failure • Delamination has been observed in some sintered retention media. • Scaling a product design up or down without conducting a detailed engineering analysis may lead to premature failures.
A widely acknowledged problem in gravel packing is plugging of wire wrapped screens and slotted liners Clays, drilling mud, cement, formation sand and pipe dope are all known plugging contributors. Field tests and laboratory evaluations have demonstrated that an acid soluble screen protector material may be utilized to prevent plugging as well as replace wash pipe and to serve as temporary blank pipe or casing. Introduction Plugging or partial plugging of wire wrapped screens and slotted liners is a common problem detrimental to the achievement of maximum productivity. Full scale tests conducted by Chevron have demonstrated dramatically that the wedging of gravel and other material in the openings of a slotted liner during gravel packing can result in severe loss of flow capacity. Field experience has also shown that circulation of fluids through a slotted liner can cause severe plugging with formation sand that has been mobilized while running the liner into the wellbore or by subsequent circulation past an open hole section. In steamed wells, the problem of a plugges liner may be compounded by the creation of thief zones caused by preferential cleaning of liner slots opposite higher permeability zones. This results in preferential and incomplete treatment of the production preferential and incomplete treatment of the production interval. In order to circumvent these problems an acid soluble coating was developed. This acid soluble coating has an advantage over the previous temporary coatings in that the dissolving mechanism is controlled by the operator and is not dependent on bottom hole conditions. The coating is insoluble in oil or gas and water, but will soften and weaken with long term exposure to water. Coatings made of wax or polymers require accurate knowledge of the bottom polymers require accurate knowledge of the bottom hole temperature for removal of the coating. Discussion The acid soluble screen protector material is composed of a mixture of inorganic magnesium salts and water. The mixture is usually applied as a thick paste to the exterior of a screen or liner. Once paste to the exterior of a screen or liner. Once applied, the paste will harden in 4 hours to a compressive strength of approximately 6,000 psi forming a coating to protect the screen from plugging or damage. The acid soluble screen protector material may also be used as a replacement for wash pipe. A screen or liner is coated leaving a 10'-15' section on bottom uncoated. Using a crossover tool hook-up, gravel can be circulated until the lower blank screen is covered. When this blank section is covered, a pressure increase will be observed. Then the tool can be lowered into the squeeze position and the gravel pumped into the formation. After the gravel pack is complete, 10–15% hydrochloric acid can be spotted on the inside of the screen and allowed to soak for 30 minutes. The acid may either be squeezed into the formation or reversed out. FIELD CASE NUMBER 1 The acid soluble screen protector material was used as a temporary casing in a Louisiana offshore well. A 300' open-hole gas well was to be completed. The upper 100' of this formation was shaley, water sensitive and very susceptible to fluid loss. In order to complete this well, an external casing packer was used to isolate the upper portion of the reservoir. (see Figure 1) Using port collars and a combination tool hook-up, the lower zone was gravel packed with a slurry containing 15 pounds of gravel packed with a slurry containing 15 pounds of gravel per gallon of fluid. After a sand-out, the excess per gallon of fluid. After a sand-out, the excess slurry was reversed out by pumping down the annulus between the acid soluble screen protector coated 4-1/2" screen and the combination tool. The combination tool (washing tool) was raised to a position inside the acid soluble screen protector coated upper screen and an attempt was made to hydraulically wash off the coating. A pressure of 2,000 psi failed to remove the coating.
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