TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractIt's a fact of life -many gravel packs plug up. As time passes, skin factors go up and production rates go down.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractA new technology utilizing a Single Step Specific Enzyme Breaker (SSSEB) process has been applied for the removal of damage caused by drill-in fluid on horizontal wells. This technique has resulted in significant improvements in well performance. Previous SEB (Specific Enzyme Breaker) technology, as it applies to xanthan, starch and carbonate drill-in fluid, focused primarily on a two step process for removal of horizontal well drill-in fluid filter cake damage; an initial SEB treatment for starch or xanthan polymer removal followed by a second treatment of acid for calcium carbonate removal. 1,2 This new SSSEB method provides an effective one step system for removing both the starch polymer and calcium carbonate components of drill-in mud filter cake formed during horizontal open hole operations.Case history information and laboratory data are presented to validate the effectiveness of the SSSEB formulation on the degradation of the filter cake formed when a starch, xanthan and calcium carbonate drill-in fluid is utilized. Previous laboratory and field data have demonstrated the effectiveness of SEB technology for degrading starch polymer. The new SSSEB method utilizes the identical starch specific enzyme product used in previous SEB treatments; however, it also employs a buffered, organic acid fluid. The organic acid reacts with the calcium carbonate portion of the filter cake as the enzyme simultaneously acts on the starch polymer. Compared to conventional high strength mineral acid systems (such as hydrochloric acid) often used for calcium carbonate filter cake removal, the SSSEB acid solution reduces the risk of fluid emulsions, formation acid sensitivity issues, secondary precipitate problems as well as safety and environmental issues. The system is also relatively slow-reacting which is important for the effective placement of the breaker fluid across the entire horizontal interval and allows for uniform filter cake deterioration.The most noticeable economic benefit resulting from the application of the Single Step Specific Enzyme Breaker system is increased production of hydrocarbons. The SSSEB technique also offers savings on rig and related charges, chemical costs and operational charges by allowing for wells to be placed on production more rapidly and not requiring follow up acid work.

It's a fact of life—many gravel packs plug up. As time passes, skin factors go up and production rates go down. Much of the money that was spent on creating a sand control completion with minimum skin may eventually count for nothing. In order to prolong the effectiveness of the gravel pack (GP) and as a added benefit reduce the need for work overs, a method was developed in the Far East to remove these fines and dramatically reduce the skin factor. The method employs relatively small volumes of a specialized HF (hydrogen fluoride) acid system, designed to penetrate into the GP and very near wellbore area. The HF acid system uses an organo-phosphonate (HV) acid to control the production of HF and to control and drastically reduce potentially damaging secondary and tertiary precipitates. The system will be referred to as HV:HF Acid in this paper. This HV:HF Acid system can be applied to any well with a screen and/or GP that has damage caused by the migration of formation fines and/or drilling mud particles. It is not limited by the type of screen or gravel nor by the length or number of sets of screens. The method has potentially enormous implications throughout the world. Any well with a GP or screen could potentially benefit from this method of treatment, including long horizontal intervals, which up to now have been very expensive to treat, due to the larger volumes of acid normally recommended. The results of this HV:HF Acid method will be illustrated by 3 case histories from the Far East, including horizontal wells. The observations from these treatments allow us to conclude that this method is highly successful, cost effective, and applicable to a broad spectrum of well conditions. The reduced stimulation volumes provide better economics, so that even long sections and horizontal wells can now be stimulated at reasonable costs. Introduction Around the world there are literally thousands of gravel packed wells which could benefit from a reliable and cost effective method for removing damage caused by fines. Many of these wells start out with relatively low skin factors and then gradually show an increase in skin as the GP, a.k.a. "the filter", collects migrating particulates. In other areas of the oil industry where filters are used (hydraulic systems, preparation of completion fluids, engine lubrication etc), filters are cleaned or replaced as they get plugged. Replacing a GP is a risky and expensive process which involves the often problematic well killing operation. Alternatively, cleaning the GP has the potential to be a much more cost effective solution. There are inherent problems associated with trying to remove fines damage from the matrix of a GP. Firstly, the fines themselves are usually composed of either quartz particles (silica), silicates and alumino-silicates (clays and feldspars) or, more commonly, a combination of these. Because the GP is filtering out some of these particles, they are generally much more concentrated in the GP area than they originally were in the formation. The only method available for removing these fines—short of doing a work over—is to use some kind of hydrogen fluoride (HF) based acid system, typically referred to as "mud acid" (as these acid systems were first developed to remove formation damage caused by drilling muds). The use of such acid systems to dissolve silica, silicates and alumino-silicates is sometimes poorly understood and can often result in the production of several different types of precipitates. Indeed, the process of HF acidizing has been described as an effort to remove more damage than the damage created by the treatment itself.1 Instances of HF treatments actually reducing production (i.e. creating more damage than they remove) are unacceptably common.

Over the past several years the coiled tubing industry has seen significant coiled tubing-related technology advancements that have supported new applications for smaller coiled tubing (CT) services, from basic onshore capillary chemical injection installations to more complex offshore CT applications 1-8 . New and older well completion and location challenges continuously redefine the boundaries of conventional CT well intervention methods especially for offshore situations which can often be difficult to economically justify. These challenges require solutions that yield better economics. Small CT technologies have recently been developed and deployed on challenging projects in Asia Pacific to provide operators with cost effective methods to maintain wellbore integrity and enhance production.A lightweight, small-footprint coiled tubing unit (CTU) has been developed in Asia allowing for the use of Small CT technology on a broad spectrum of well service applicationsThis OTC paper will cover the specifics of an application of Small CT technology in Malaysia. Numerous challenges will be reviewed including using small (1-in. OD) CT pipe, small CT motors and working inside a restricted completion with high dogleg severity and a 70 degree hole angle. A total of 23 CT runs, inclusive of 14 CT perforation runs, were performed and the entire job was completed safely, without any major operational issues and delivered a gas rate of 15 MMscfpd.The Small CT equipment package is very comparable to a more conventional, larger CTU spread. A Small CT package can consist of a lightweight and small-footprint CT unit, a small nitrogen unit, reduced-size nitrogen tanks and compact pressure pumping equipment. As an example, for a gaslift type job using Small CT versus conventional CT equipment, the equipment footprint is reduced by 40% and the equipment weight is reduced by 46%. The small footprint and light weight of the Small CTU is especially beneficial where crane or deck space limitations are challenges. Small CT equipment can be customdesigned to suit most land or offshore applications, and the CT pipe can be installed on a semi-permanent basis (such as small capillary installations) or deployed as a work-string for well intervention programs.Application of this technology has the potential to substantially reduce operating costs, logistical support and risk exposure and can be applied to both onshore and offshore environments worldwide. Wells that were once considered plug and abandon candidates due to economic, technical challenges or accessibility may now be candidates for Small CT technology solutions. CT Run 4Perforation #1 The objective for this run was to perform an equalization shot from depth 2225-2235m MD-RKB. Start RIH with an equalizing shot at 15m/min and stop at 2261m MD-RKB (actual TD 2272m MD-RKB). CT Run 5 Perforation #2 The objective for this run was to perforate the interval 2220.7-2229.5m MD-RKB. RIH gun BHA with THP=550psi and stop CT at depth 2259.6m MDRKB to correlate depth. CT picked-up to top of the de...

Excessive water production is consistently burdening the oil industry, especially as lifting and facility costs rise and disposal of produced waterbecomes increasingly difficult, expensive and environmentally sensitive. Apreviously developed amphoteric polymer material (APM) (SPE Paper No. 14822)has been successfully applied in Indonesia. This product reduces volumes of produced water and very often increases hydrocarbon production by effectivelyreducing the permeability to water without significantly changing the formation permeability to hydrocarbons. This paper will review the mechanism, application and associated lab results by which the APM polymer reduces water cut with the primary emphasis on the Indonesian case histories and placement techniques. Results indicate that high permeability sandstone reservoirs, with water production problems, can benefit from APM treatments. The product cansuccessfully and economically reduce water production with the added benefit of increased hydrocarbon production often noted. Laboratory and field results indicate good product application under high shear situations and at temperatures up to 275 F. Careful candidate selection and good placement techniques, in conjunction with production logging to determine water location, are important to the success of APM jobs. Introduction Oil company profitability is suffering in high water cut areas and a focus on methods for water control is paramount in the engineers plans to increase profits. Wells treated during the late 1995/early 19% Indonesian study showed a water cut reduction, an increased oil cut, and a reduced total volume of produced fluid in the field enabling more wells to be placed on line and not exceed water management capabilities of the production facilities. High water cuts are often due to common oilfield phenomenons such as waterfingering, coning or early breakthrough during flooding projects. Water production occurs in many oil and gas wells primarily because of the higher mobility of water relative to hydrocarbons. This water production can take place on the initial completion or later in the life of the well. Small amounts of water may not create problems; however, when the production of water becomes excessive, consideration of water reduction is often necessary. Operators are often required to shut-in high water cut/low oil producing wells so that they can meet facility capabilities even though the reservoir is known to contain economic quantities of hydrocarbons. Large quantities of water add to the overall dollar per barrel costs of producing a well. More water can mean additional lifting, separating, and treatment costs as well as the environmental concerns that are associated with water disposal. Hydrocarbon production can also be reduced by high water production. The increased wellbore hydrostatic head often reduces the available energy to drawdown the reservoir. Higher density water in the tubing string can lead to early shut-in or the installation of unplanned artificial lift equipment. The relative amounts of gas, oil and water present at any particular level in the reservoir will determine the most likely fluid(s) that will be produced by a well completed at that level and will also influence the relative rates of production. P. 429