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.
In the past, high-viscosity fluids have been the preferred method for increased proppant suspension and transport. This methodology has been effective using systems such as borate-crosslinked fluid with the downside of considerable damage to the proppant pack, typically resulting in about 85% percent regain conductivity. While this may still be acceptable, the major limitation of these systems is the additional loss of needed fracture length. Often, with low viscosity fluids such as linear gels and friction reducers, fracture length may be established allowing breaks into the secondary fractures and mechanical reactivation of the pre-existing natural fracture network may be enhanced. However, these low viscosity fluids cannot offer efficient suspending characteristics within the fracture under static conditions, which may lead to early settling. As a response to this industry demand, a novel fluid has been developed to optimize the hydraulic fracturing process by enhancing proppant transport with reduced friction losses, less fresh water requirements and smaller footprint of pressure pumping equipment. Novel fluid technology from which the polymer was engineered to form a network of packed structures from polymer associations providing the maximum proppant suspension, breaking with the traditional concept relying on viscosity to enhance proppant transport during treatments, is described with extensive experimental testing. The results show that the fluid exhibits outstanding properties and benefits to transport proppant without settling in addition to a considerable reduction in fresh water requirements and maintenance costs associated with surface equipment footprint, as the current trend is unsustainable. New physics consisting of a hybrid rheology analytical model and fluid structures to correlate elastic fluids rheology parameters, firstly, n′ and k′ values, and secondly the storage, and loss moduli profile (G′ and G″ accordingly), is presented. The complex fluid behavior deviates from common rheology models and, its elastic properties, such as storage modulus (G′), loss modulus (G″), and angular frequency (rad-sec) are discussed in the context of the unique fluid characteristics of a network of packed structures from polymer associations. Physics-based analytical model results compute the viscosity, and elastic parameters based on shear rate to calculate the pressure losses along the flow path from surface lines, tubular goods, perforations, and fracture, optimizing horse power requirements based on reduced pressure loses, will be presented [16]. The presentation will demonstrate that such physics and unique fluid behavior are achieved via a novel elastic and a network of packed structures from accociative polymer fluid, having proper proppant suspension, effectively placed at low viscosity, less fresh water requirement, low injection pressures, with no settling and 98% retained conductivities.
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^
The subsurface injection of drilling waste has become an increasingly popular and well-accepted technology over the last several decades. The popularity of this technology is primary spurred by its economic advantages in meeting more stringent drilling waste management requirements, especially in remote and environmentally sensitive areas. Furthermore, its use has become more attractive with the dramatic development and improvement in the processes associated with surface and sub-surface engineering, fracture modeling, risks identification and mitigation options, injection monitoring and in-depth pressure analysis. Together, these advancements have improved considerably the assurance and efficiency of waste injection operations worldwide. Nevertheless, despite the tremendous advancements in the fracture modeling attained from subsurface feasibility studies, a major uncertainty exists with the propagation of multiple-fractures that apparently accompanies the intermittent batch injection process, essential to the drilling waste injection operation. The propagation of multiple-fractures, along with their orientation and complexities, strongly influence the fracture design, ultimate disposal capacity and injection pressure behavior. Consequently, this uncertainty is a critical issue, both in drilling waste injection and re-fracturing in conventional stimulation treatments. This paper describes the evolution of understanding of multiple-fracture mechanics in drilling waste injection, starting from the conventional "wagon-wheel" uniform disposal-domain concept to the branching multiple-fractures approach that becomes practical through mathematical computations of near-wellbore changes in the stresses resulting from prior fracture creation and solids accumulation. Moreover, the authors present four potential scenarios of subsequent fracture initiation and propagation during intermittent injections, and provide revised re-assessment of data from the joint industry Mounds Drill Cuttings Injection Field Experiment.
fax 01-972-952-9435. AbstractThe progression of new field developments, including brownfield and deepwater, subsequently increases the volume of cuttings and production waste, and particularly produced water, considerably. The economical impact of missing drilling and production targets due to the failures in the drilling waste injection process represents high risks that demand sound engineering processes to ensure injection assurance.This paper describes the solution and detailed pressure monitoring methodology implemented to maintain safe injection assurance via regular disposal fracture diagnostics. Timely identification and a thorough evaluation of non-ideal pressure signatures observed during injection and post shut-in periods provided critical information required to detect subsurface anomalies. This can be an effective tool for the subsurface risks identification and characterization.The application of comprehensive fracture-mapping techniques is a major step in mitigating the environmental risks posed by waste. Waste mapping represents valuable information, not only in the overall planning of drilling operations, but in the fundamental and invaluable need to provide sound engineering for waste location and fracture containment assurance, thus minimizing environmental impact. Previous, oversimplified interpretations of multiple fracturing systems (or so-called uniform disposal domain) and new fracture initiation process are demonstrated to be in apparent conflict with fracture mechanics, stress calculations and the general principles of physics.The authors also describe the results of pressure analysis conducted in a North Sea injection well, which simultaneously was used for production. The well was utilized successfully for Cuttings Re-Injection (CRI) and for the disposal of produced water. The success of the operation was a direct result of close monitoring of key injection parameters and indepth analysis of injection pressure, despite risky geological conditions. Abnormal pressures increases and restrictions observed during injection were mitigated and addressed via a proper root-cause engineering and sound pressure diagnostic process. The drilling waste injection took place below a 13 3/8-in. casing shoe through the B annulus, in an open-hole section at the depth of 1220m TVD with a 24 0 deviation in the injection interval. The injection took place in close proximity to a major fault axis.
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