In the Mallik 2002 Gas Hydrate Production Research Well Program, formation tests with a Modular Formation Dynamics Tester (MDT)TM tool were conducted and the test results were analyzed using conventional pressure-transient test-analysis methods. The reliability of the reservoir-parameter estimates, however, is uncertain because of the abrupt change in gas hydrate saturation associated with gas hydrate dissociation during the tests. To investigate the applicability of these methods, the bottomhole-pressure responses during MDT tests in the hypothetical and actual gas hydrate zones were predicted using a numerical simulator and then analyzed by conventional test-analysis methods. This study revealed that the conventional methods might indicate the average effective permeability over the area of gas hydrate dissociation, and that they might accurately suggest the radius of gas hydrate dissociation only when applying appropriate multiphase-fluid properties and production rates to the cases with high gas hydrate saturation.

Summary Andrew field in the U.K. Continental Shelf, which is operated by British Petroleum (BP) Exploration, is being developed using horizontal oil producers and completed with cemented liners. The main challenges of perforating these wells are maximizing well productivity by avoiding formation damage, minimizing the possibility of sanding, maximizing ultimate hydrocarbon recovery, perforating long horizontal sections safely and efficiently, optimizing the economic value of perforating, and minimizing perforating debris. In general, to avoid impairing well productivity, it is best to perforate the underbalance. However, the advantage is compromised, because of the fluid invasion and loss-control material, if a well will be killed when the tubing-conveyed perforating (TCP) guns are removed. Existing deployment methods with coiled tubing (CT) enable perforation and subsequent gun removal in an underbalance condition. Unfortunately, various limitations would require multiple runs with CT for perforating each horizontal well in the Andrew field, which would result in significant time and on balance perforation for each subsequent run. The combination of the newly developed mechanical ball valve and the deployment of TCP guns with hydraulic workover units enables long horizontal wells to be perforated in one run in underbalance, and enables the guns to be removed without killing the well. Specially engineered guns and perforating charges are used to minimize sanding and gun debris. This paper describes how these new technologies, used for perforating operations, meet many challenges. The same technologies can be used readily for perforating other long horizontal wells with similar problems. To date, three horizontal wells in Andrew field were perforated successfully with the method described in this paper. The initial results indicate that the combination of the cemented liner completion, the engineered perforation systems, and the correct TCP gun deployment method using the mechanical deployment valve have contributed to improve well performance, to reduce cost, and to improve operability and safety in long horizontal wells.

The comparison of today's slickline capabilities with its early usage for routine remedial workovers and maintenance best illustrates the significant advances that have occurred within slickline technology. Today, for example, slickline can be used to I) set and retrieve slickline-retrievable safety valves or plugs, 2) open and close downhole circulating devices, 3)retrieve accurate depthhime data for correlating with memory production surveys for well diagnostics (problem identification) reservoir description, or flow analysis, 4) provide accurate correlation of tubing casing collars, and 5) pull and run multiple flow controls set packers and other downhole equipment without explosives; setting monobore tools; and other perform other well interventions that are dependent upon measurement accuracy. Less than a decade ago, slickline was only considered for mechanical well workovers. This paper will discuss the newly developed technology that allows slickline to economically provide alternatives to services traditionally reserved for other, more costly options. Case histories will be used to illustrate the enlarged scope of services and how the equipment combines to provide the innovative low cost service options that the industry has been seeking. Introduction Economic initiatives are usually the drivers of new technologies, and thus, reacting to the significant decline in the oilfield climate during the last decade, no era has been as momentous in providing stimuli for operational change. Unfortunately, operators who are seeking new methods usually look to new technologies as the potential problem solvers, and in so doing, overlook enhancements to the older, proven technologies that could provide the cost efficient alternatives they want. This has been the case with slickline. Until the resurgence of investigation into new strategies to meet the oilfield cost constraints of the last decade, slickline service was only considered for routine mechanical workovers. Who would have considered using slickline to set a packer in the early 90's. The capabilities that have changed the profile of slickline service from one of routine mechanical well work overs to a multi-faceted service technology are derived from the new slickline tools that can be used independently or combined to further enhance the scope of services. The equipment includes an electronic triggering device (ETD) that enables safe detonation of explosive devices, a battery-operated, electro-mechanical tool that sets wellbore devices on slickline and braided line without explosives, an electronic measurement system that automatically corrects measurement inaccuracies resulting from line stretch and environmental stress factors, a slickline collar locator (SLCL) that accurately verifies collar locations in a tubing string, and data job loggers or acquisition software systems that connect to the electronic measurement system to graphically record dynamic wireline information.

A novel technique which offers scope for significant rig time savings has been successfully applied in the Brent Field in the UKCS. This technique involves running a memory production logging string containing spinners and pressure/temperature gauges in conjunction with electric line perforating guns. It has been applied in three Brent wells to date (two producers and one injector). In each case MPLT data was acquired both before and directly after firing the guns, without having to pull out of hole. Full memory data recovery was achieved for all runs; data quality was comparable to that of typical electric line PLT's. The three runs were performed with varying applications in mind:determine the extent of crossflow prior to obtaining a fluid sample,perform leak investigations on recently set Casing patches anddetermine gross production/injection splits. Each of these applications was carried out successfully. In addition, six to eight hours of rig time were saved in each case. This confirms the potential for significant cost/time savings, particularly if the technique is extended to coiled tubing operations. Similarly, the technique could be extended to include other PLT sensors and/or fluid sampling tools. Although this technique is unlikely to replace the logging of normal electric line PLT's, we believe that it holds great promise for fit for purpose production logging applications which don't require real time intervention. Introduction By applying tried and tested technology in a novel fashion, significant rig time savings can be achieved. An example of this is the application of standard memory production logging technology while perforating. Recent experience in the Brent Field in the UKCS has shown that it is feasible to run both memory pressure/temperature gauges and memory spinners below perforating guns and thus obtain MPLT information before and after perforating without pulling out of hole. By combining the surveys with the perforating operations, rig time can be saved without sacrificing data quality. In this paper we will discuss the technical details of the tools used and outline the results of the three operations performed to date. Tool specifications A schematic of the MPLT tool string as run in Brent is shown in Figure 1. Combined tools are, from the bottom: fullbore spinner (FBS), centraliser, in-line spinner (CFS), pressure/temperature sonde (SPLS), memory downhole recorder (MDR), adapter, sapphire crystal gauge (SLSR) and shock absorber. Tool selection was based on two criteria: robustness and reliability. Robustness is required because the tools are exposed to the shock of the gun detonation. Reliability is particularly important as, being memory tools, there is no means of knowing whether or not they have functioned properly until they are recovered at surface. It is for this reason that, in order to increase the chances of full data recovery, two spinners and two pressure/temperature gauges were run in tandem. The FBS and CFS that were used are identical to the spinners used in field-proven electric line PLT strings. There are several sizes available to cater for different casing sizes and flowrates. The specifications of the spinners used can be found in Table 1. The SPLS and SLSR gauges are two different types of pressure/temperature gauges. The SPLS consists of a Quartzdyne sensor, and is run in conjunction with the MDR (see below). The SLSR consists of a sapphire crystal sensor, and is a stand alone memory gauge (i.e. with its own recording facility). It is run both on slick line and during DST/TCP operations (in a gauge carrier above or below a packer). Specifications of both gauges are summarised in Table 2. P. 535^

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractBeringin field D-structure (Beringin-D) is located in South Sumatra, Indonesia, operated by Perusahaan Pertamnabgan Minyak dan Gas Bumi Negara (Pertamina), DOH Prabumulih. Since its discovery in 1987, some 30 wells have been drilled and current total oil production is approximately 1,700 BOPD. The geological structure of this field is homocline with several faults across the field and several late Oligocene/early Miocene hydrocarbon-bearing sandstone layers are deposited on basement or on shale by on-lapping.In the past, formation damage problems were encountered in Beringin-D and matrix acidization was applied to improve well productivity. However, the results were mixed and the main reason for failed acidization was thought to be lack of knowledge of clay types in the formation; thus, composition of the treatment fluid was not optimized. Therefore, to identify clay types present in the formation, an ECS * Elementary Capture Spectroscopy log was run on Well BRG-19. The ECS tool is a wireline-run neutron device that can detect important elements in openhole or in cased hole. Combined with NGS * Natural Gamma Ray Spectrometry log and other information, a comprehensive formation mineralogy analysis is possible.Prior to obtaining the ECS/NGS logs, higher than 10% montmorillonite (smectite) concentration was assumed and sandstone acid (SSA) had been commonly used for Beringin-D wells. However, the log on BRG-19 revealed that the interval of interest contained 8% kaolinite and 3% montmorillonite. On the basis of this new finding, standard acid was used instead of the SSA, and the result showed 100% oil production improvement compared to the average 30% * Mark of Schlumberger improvement in the past. Also, the SSA costs approximately twice as much as the standard acid.The ECS and NGS logs helped us identify and quantify clays in situ, and we used this information to optimize matrix acidization through a field case.