Summary In this paper, we present the results of successful applications of polymer gels to control water production in Mexico. We discuss three case studies that used a systematic methodology to correctly diagnose near-wellbore water channeling behind the casing. The methodology uses diagnostic plots based on the historical behavior of the water/oil ratio (WOR) as a function of time. These include correlation with information from original cement bond logs (CBL's), oxygen-activated logs during production to effectively determine the origin of the water, and saturation logs to determine the water levels independent of the salinity of the water produced. In addition, we present successful applications of polymer gels to re-establish zonal isolations in the three case studies previously mentioned. We discuss gel placement and present the procedure followed in each case, evaluate a water injectivity test followed by a temperature log taken before gel placement to determine the height propagation of the water, and anticipate potential zone damage of adjacent producing intervals during gel placement. In one case, a new interval completed perforating through the gel with excellent results. Another case involved a zone abandonment with gel, in which positive pressure was tested with 35 and 70 kg/cm2 wellhead pressure at 2500 m. In all cases, the advantages of gel treatments over common cement squeezes are discussed. Finally, we present the treatment results, including the analysis of pressures recorded during gel placement and the oil and water production before and after treatment. Introduction One of the main problems encountered in old wells and wells originally cemented under low reservoir pressure consists of hydraulically isolating different intervals to allow proper production of the zones of interest. This lack of isolation has caused undesired fluid movement behind the casing, generating confusion about the actual levels of the oil/water contact (OWC) and causing premature abandonment of oil reserves. We present a methodology followed in northern Mexico that corrects water channeling behind the pipe with chromium-crosslinked polymer gels. The advantages of using gels over cement include their flexibility for pumping without a workover rig, higher control of setting time, ease of cleaning, lack of milling time, and superior operations cost without risking effective treatment. Included in our methodology is candidate selection with diagnostic plots that allow us to identify near-wellbore flow that correlates with CBL's, indicating poor cement. Finally, we discuss three field case studies in Poza Rica, northern Mexico. The data for each case are presented, including saturation logs, production logs, density logs, and water flow based on the activation of oxygen to monitor the movement of water through a channel. Corrections to water flow are also presented, as well as a detailed overview of the execution and results, showing treatment effectiveness. Near-Wellbore Flow The problems associated with water production and its control present a challenge to reservoir and workover engineers. The central issue lies in defining the source of the water and determining whether the water production of a given interval is necessary to the associated oil production. Therefore, we must define two kinds of water production - bad and good. The production of water is considered good when it sweeps an oil bank and carries important oil production with it. Bad water inhibits the oil production of an interval because of aquifer coning, injection-water channeling, or well-vicinity water flow. Therefore, knowing the source of the water produced is fundamental in defining the problem. The presence of water in a production interval brings questions about the actual level of the OWC. In many cases, this uncertainty causes premature abandonment of oil reserves assumed to be water-invaded. Near-wellbore flow (Fig. 1) is one of the most prominent causes of confusion because of several factors: poor cement bond, caverns formed by sand production, channels in the formation, natural fissures, hydraulic fractures, reduced oil flow caused by formation damage, and frequent stimulation in the near wellbore. Poor Cement Bond. Several factors may explain a poor cement bond. First is the exposure of the cement to adverse conditions of temperature, pressure, and perhaps sulfate waters, which cause the cement to deteriorate and create potential channels behind the pipe that can allow adverse fluids to flow. This is more likely to happen if problems such as low-pressure zones, gas migration, or poor design of washers and spacers were encountered during the primary cementing job. Today, this problem represents one of the most important causes of uncertainty regarding the OWC and a water-invaded interval. Caverns Formed by Sand Production. One of the main problems related to formations with sand production is that caverns can be created that can be detrimental to the hydraulic isolation of the production interval. This causes a potential for communication with a water-invaded zone. These problems are common in friable, poorly consolidated sandstone. Channels, Natural Fissures, and Hydraulic Fractures. Channels, natural fissures, or fractures in the formation create hydraulic communication through an interval. This may allow the water in a zone to percolate up to the production interval, negatively affecting the oil. The effect of natural fractures has been widely discussed in other publications.1–3Fig. 2 illustrates channeling through a fracture. Critical production rates have a direct influence on the invasion of these channels by water and thus on its detrimental effect on oil production.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractHydraulic fracturing using proppants is a well established technique for increasing well productivity.However, uncontrolled mineral scale deposition within the proppant pack can result in reduced conductivity and fracture performance, thereby devaluing the initial investment in the fracture. To protect this investment an active scale control strategy is required especially when executed in the presence of a water flood. A number of different techniques have been proposed and used historically, however they have all suffered with one or more drawbacks. These drawbacks have included excessive volumes, poor placement control, short treatment life and / or the potential for fines and sand generation and pack instability. The ability to place scale inhibitor within the voids of a porous proppant offers a robust technique for placing a large amount of scale inhibitor throughout the proppant pack while its controlled released protects the productivity of the fracture.Previous papers have described the development of porous, scale inhibitor impregnated proppants and highlighted the initial returns from field trials performed on land wells on the North Slope of Alaska. The impregnated proppant technology has now been further developed and two treatments have recently been deployed in the North Sea. The treatments were both designed to stimulate production and to protect the fracture against future scaling scenarios. This paper will describe the design criteria used to select this method of protecting the future performance of the fracture. In addition this paper will describe the design and execution of the treatments while highlighting the fracture performance and scale inhibitor return profiles generated by recent treatments performed in the British and Norwegian sectors of the North Sea.
The San Jorge Basin is characterized by multilayer formations requiring proppant fracturing as a completion method in order to achieve oil production at commercial levels. As fields are arriving to a mature stage they require continuous improvements with regards to fracturing techniques. Typically viscous polymer based fluid had being used with acceptable results for proppant transport and fracture placement; however these fluids are known to generate undesired effects such as uncontrollable height growth, significant proppant pack damage, lengthy clean up times and high friction pressures. In recent times, polymer-free viscoelastic surfactant-based (VES) fluid systems have been introduced in the industry as an improvement over polymer-based fluid. Nevertheless, VES were known up to now, for their limitation to withstand elevated temperatures. Detail laboratory studies proved that a novel VES high temperature (HT) version was also feasible for the given conditions of this high temperature formation. Since the reservoir temperature exceeded the technical limits of even this HT fluid, simulations indicated that a series of cool-down brine stages would allow the application of this fluid at this temperature (280F). The characteristic of the fluid allowed the treatment to be confined in the limited layer thickness between weak barriers avoiding growth into water - or non - productive zones, resulting in reduced fluid and proppant volumes. Field implementation proved also to be successful in terms of operational simplicity, reduced clean up time and consequently work over rig cost savings. Overall, the use of polymer-free fluids improved well productivity. Design, laboratory studies, temperature simulations confirmed by downhole measurements, field implementation and results of the first VES HT fluid application in the El Tordillo field are presented in this paper. Four different zones were successfully treated in the first well application at various reservoir conditions presenting a wide range of permeability and temperatures. Introduction The oil producing sands of the San Jorge Basin store important hydrocarbon reserves, covering an extensive area across South Argentina. The basin-fill was by fluvial deposition during the Cretaceous period. Wells are typically vertical and penetrate several thin laminated layers, of thickness ranging between one to eight meters. (Figs. 1 and 2) Furthermore, imprecise clay volume determination, uncertainty in the lithology, rock texture, structure and formation damage, are all aspects that represent a major challange in managing reservoirs in the San Jorge Gulf Basin. To make matters worse, the low well productivity offers operators only a marginal return on their investments. In an effort to increase productivity, the hydraulic fracturing technique has been adopted since many years, being in most cases the only method of achieving commercial production levels. A typical San Jorge Gulf Basin well has an interval of interest located between 800 to 1200 meters, with dozens of sand beds ranging from one to four, five or eight meters thick, many of them strongly laminated 1. This productive intervals were formed during the Cretaceous period, and is of continental origin, covering several formations whose names depend on the geographical area (see Fig. 2). The lithology changes from nine sands at the bottom of the well to twelve sands at the top of the productive interval. Many of these sand beds contain hydrocarbons but produce oil, water or gas, depending on the fluid saturations, relative permeabilities, rock and fluid characteristics. Presently fluid prediction success rate varies between 65% and 80%.
Offshore operations are extremely expensive because of the operational environment and the necessary infrastructure. In this environment, emphasis is placed on high-efficiency operations based on specially tailored solutions combining available resources with new technologies. This results in a significant impact on operational efficiency by lowering costs and ultimately increasing hydrocarbon production. To introduce greater efficiencies in offshore operations, a horizontal openhole candidate well was selected to be equipped with a permanent completion system that would enable multiple fracturing treatments. Later, it was determined that by using a novel viscoelastic polymer-free surfactant-based fluid, the entire operation could be performed in a single operation, adding additional savings to the process and improving efficiency. Interpreted openhole images and advanced sonic logs were used to determine the optimum completion configuration and to select favorable fracture initiation points and treatment designs. Because a specialized fracturing vessel tailored for operations in the Black Sea was not available, a supply vessel was used. The vessel had all required fracturing equipment rigged up and secured on decks. To enable sufficient fracturing fluid volume for placing three propped fracturing treatments in a single pumping operation, a polymer-free fracturing fluid was formulated and mixed with seawater continuously. This novel multistage fracturing system was introduced in Europe for the first time. Results indicate a sustained increased production. Because of this success, additional wells are scheduled to be stimulated using same approach in the following months. Introduction The Lebada Vest field is situated ~95 km offshore Romania in the Black Sea. This field was discovered in 1984 and put on production in 1993. Since then, numerous vertical oil and gas wells were drilled and completed (Fig. 1). The wells were produced initially in natural flow and later equipped with gas lift to enhance ultimate hydrocarbon recovery. The target reservoir is a Cretaceous-age formation located at depths of ~1,900-m true vertical depth (TVD) composed of varying shale, sandstone, and carbonate content. The laminated pay zone is generally formed by streaks with permeability ranging from 0.1 md to 2.0 md and average of 0.8 md. Reservoir rock porosity ranges between 15% and 22%. Bottomhole static pressure (BHSP) at ~1,850 m true vertical depth sub sea (TVDSS) sub sea is ~220 bars and bottom hole static temperature (BHST) is 93°C.
This paper presents the results of successful applications of polymer gels to control water production in Mexico. Three case studies are provided where a systematic methodology was employed to correctly diagnose near-wellbore water channeling behind casing. The methodology discusses the use of diagnostic plots based on the historical behavior of the water-oil ratio as a function of time. Including, correlation with information from original cement bond logs, oxygen activated logs during actual production to effectively determine the origin of the water, and saturation logs to determine the actual levels independently of the salinity of the water been produced. In addition, the paper presents successful applications of polymer gels to re-establish zone isolations in the three case studies mentioned above. It discusses gel placement and presents the procedure followed in each case, evaluation of a water injectivity test followed by a temperature log prior to gel placement to determine height propagation of the water and anticipate potential zone damage of adjacent producing intervals during gel placement. One case is discussed where a new interval was completed perforating through the gel, with excellent results. The other case, presents a zone abandonment with gel were positive pressure tested with 500 and 1,000 psi well head pressure at 2,500 meters. In all cases advantages of gel treatments over common cement squeeze are discussed. Finally, results of the treatments performed are discussed including the analysis of pressures recorded during gel placement. The oil and water production prior and after treatment are presented. Introduction One of the main problems encountered in old wells and in wells that were originally cemented under low reservoir pressure, consist in granting hydraulic isolations between the different intervals to allow proper production of the zones of interest. The lack of isolation has caused, among other things, undesired movements of fluids behind casing generating confusion of the actual levels of the oil-water contact and originating premature abandonment of oil reserves. This paper presents a methodology followed in the north of Mexico to correct channeling of water behind pipe using chromium crosslinked polymer gels. It presents the advantages of using gels over cement, including flexibility for their pumping without a workover rig, higher control in setting time, easy-to-clean, no milling time, and superiority regarding operation cost without risking treatment effectiveness. Included in the methodology is the candidate selection using diagnostic plots which allows to identify, among others, near wellbore flow which correlates with cement bond logs indicating poor cement. Finally, three field case studies corresponding to the north of Mexico, Poza Rica, are discussed. Analysis of the information available is discussed in each case, including saturation logs, production logs, density logs, and water flow, based on the activation of oxygen, to monitor the movement of water through a channel. Corrections to these flow of water is presented including a detail overview of the execution and of the results showing the effectiveness of the treatments. Near Wellbore Flow The problems associated with water production, and its control, represent a great challenge to the reservoir and workover engineers. The key of the problem lies in defining the origin of the water and determining whether the water production of a given interval is necessary to the associated oil production. Therefore it is required to define two kinds of water production: bad and good. P. 415^
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