Summary A decline in injectivity in water injection wells can have a large impact on the economic feasibility of offshore water disposal operations. A case study is presented for an offshore Gulf of Mexico water injection project. Data are presented for five typical offshore wells for which a rapid decline in injectivity was observed due to water injection. The wells were successfully acidized every few months over a period of 2 years. An analysis of the data indicates that in injection wells that are not fractured, such declines in injectivity may be expected even for relatively clean injection water. A comparison of the different completion types indicates that both open hole and perforated completions would have yielded similar results. Cleaner water would have improved the situation but at a substantial cost. Fracturing the injection wells appears to be the only plausible way of substantially increasing the half life of such injectors. In cases where reservoir conditions dictate that the wells not be fractured, the economics of periodic stimulation vs. the cost of installing surface facilities for cleaning up the water should be evaluated using models for injectivity decline. "What if" simulations conducted to study the impact of different process parameters such as injected particle size and concentration, injection rate and reservoir properties were found to be a useful tool in specifying water quality requirements. Introduction The injection of water for pressure maintenance and waterflooding applications or the disposal of produced water is becoming an increasingly important issue in the management of produced fluids. Most mature oil and gas producing regions of the world currently have a high ratio of produced water volume to produced hydrocarbon volume. Large volumes of produced water need to be dealt with for disposal purposes. In offshore operations, the injection of sea water for pressure maintenance or for waterflooding is becoming increasingly common. For these reasons, it is imperative to have reliable models to predict the behavior of water injection wells. Barkman and Davidson1 provided a method for estimating the half life of an injection well when the reservoir properties (kh) and water quality are specified. This method has been extensively applied to evaluate injector performance. Estimates of injector half life based on this model provide us with an order of magnitude estimate of injector half life. More recent models by Van Velzen and Leerlooijer,2 and by Van Oort et al.3 provide us with a basis for using core data in predicting injector half lives. Models for injectivity decline for injection wells with various types of completions such as perforated wells, gravel packed wells and fractured wells have been provided by Pang and Sharma.4,5 Their models allow us to either use core flow test data or empirically derived filtration parameters that can be used in estimating the performance of injectors. In this article, we present a case study of the application of these models to five water injection wells in an offshore environment. The results of the simulation study clearly point to the usefulness of conducting such simulation studies to obtain the optimal water quality requirements which dictate the surface facilities required for maintaining specified injection rates. The case study presents a unique data set for unfractured injection wells in which the performance of the injectors has been carefully monitored over the duration of the project. The quality of the injection water and the procedures taken to treat the water have also been extensively documented. Our main focus in this article is the injectivity decline that is caused by injected fines and their impact on injector performance. Water Injection Project History The goals of this water injection project were to maintain reservoir pressure in the target sand. The target sand is completely unconsolidated and only slightly compacted. Five injectors were drilled and completed below the oil-water contact in the target sand. Each well has a permeability height (kh) product in excess of 53,000 md-ft. (Table 1). Based on reservoir properties and expected injection water quality it was determined that injection rates of 50,000 BWPD could be sustained in radial flow. Avoidance of fracturing was essential to prevent early water breakthrough and to maintain water injection in the target sand. Because the waterflood injection rate target needed to maintain reservoir pressure was essentially the same as the facility injection capacity, out of zone losses could not be tolerated. Well Completions All wells were gravel packed to allow the wells to be produced if necessary to remove near wellbore damage. Wells were underbalance perforated, gravel packed with 20/40 mesh sand and completed with 12 gauge wire wrapped screens. Each well was acidized prior to gravel packing. Significant volumes of viscosified and/or crosslinked materials were employed for fluid loss control after gravel packing operations in all wells. The initial injectivity of all wells was low. Small stimulation treatments were performed with 10% HCl and injectivity increased dramatically but declined rapidly with time. As discussed in more detail later, extensive foam diverted HCl and HCl/HF stimulation treatments were then performed, which resulted in the wells attaining their designed injectivities. However, injectivities again declined more rapidly than expected. Waterflood Facilities Seawater is taken from 150 ft subsea, deoxygenated and filtered through primary multimedia filters and secondary cartridge filters. Five µm filters were used in some wells for a period of time but were found to be expensive to operate since they had to be replaced twice a month. In all cases these filters were replaced with 10 µm filters. As discussed later, the resulting change in water quality was clearly reflected in the well injectivity. Oxygen is taken to 200 ppb by countercurrent gas stripping and chemically scavenged to <10 ppb. A combination of continuous and batch treatments with sodium hypochlorite is employed to control bacteria. A scale inhibitor is added because the water shows a slight calcium carbonate scaling tendency.
Injectivity decline due to particles in the injection water takes place to some degree in most injection wells. To understand and predict this decline requires knowledge of the rate of particle deposition for the water/formation system considered. The rate constant for particle deposition is commonly referred to as the filtration coefficient. The filtration coefficient is a dynamic quantity and changes with the number of previously deposited particles. Many investigators have carried out extensive theoretical and experimental work aimed at determining the filtration coefficient under varying conditions. This paper presents a review of past work and its application to injection wells. Tables presenting experimental values for the filtration coefficient as well as theoretical and empirical correlations are reproduced and evaluated. Finally, a new method of determining the development of the filtration coefficient with time, utilizing a concept of critical porosity, is outlined. In particular, this method includes a correlation for the transition time, i.e. the time when an external filter cake starts building on the wellbore. Introduction Injection of particles into porous media with subsequent deposition and permeability decrease is an interesting fundamental problem which is of great importance in many engineering branches, e.g. the design of water injection programs. In designing a water injection project, the engineer would like to know the performance of an injector as expressed e.g. in terms of its half-life for a given quality of the injection water. To determine the injectivity decline for an injection well due to particles in the injection water, we need to:Determine the concentration of deposited particles as a function of distance from the wellbore and time. This requires us to know the initial filtration coefficient (defined below) as well as the variation of the filtration coefficient with time. In addition, a number of parameters describing the water, the injected particulate material and the formation must be known.The deposited particle concentration must be converted to a permeability distribution around the well from which the corresponding skin factor can be deduced.Knowing the near-well permeability (skin factor), the change in injectivity is easily determined for openhole completion. Equations for other well completion have been developed, see e.g. [1]. The first step in this process, the determination of the filtration behavior is crucial for the correct prediction of injectivity decline, and is the topic of this paper. Basic equations governing particle convection and deposition When a suspension is injected into a porous medium, various forces act between particles and grains, causing some particles to adhere to the pore walls. Neglecting diffusion, the mass conservation equation for the particles in an incompressible fluid can be written (1) Here, c is the fraction of suspended particles per unit liquid volume, is the porosity, u is the superficial (Darcy) velocity and is the volume concentration of particles per unit filter volume, Eq. (1) states that the net increase of particles within an infinitesimal filter volume equals the particles entering the volume on the upstream side minus the particles leaving the volume on the downstream side minus the loss of particles to the formation through deposition. The change in porosity is usually slow, allowing the following 1-dimensional approximations of Eq. (1) to be derived: P. 353^
Summary Selecting an effective scale inhibitor for squeeze application at 170°C is not a simple task. The traditional thermal-stability test of aging the chemical in bulk is often perceived to be too harsh. This results in many promising products being rejected because of their apparent degradation at temperature. The alternative of conducting the aging test inside core materials, which is more representative of the downhole conditions, is not a novel idea. However, to date, no definitive data are available to substantiate such a process and quantify the difference between the two methods. This is mainly because of the difficulties and complexity in conducting such an experiment at a high temperature over a long period of time. In this paper, the results from a recent investigation are presented. We describe the detailed procedures of the planning and execution stages, lessons learned, and pitfalls that must be avoided. A scale inhibitor was aged with two different methods: one in bulk, as commonly practiced in the industry, and one inside a sandstone core. The aging period varied between 45 days for the bulk and 110 days for the last desorbed sample from the core. The samples that were aged inside the core retained much of their inhibition efficiency, while those aged by the traditional method (bulk) lost nearly all their effectiveness. These results demonstrate clearly that the conventional method of thermal aging in bulk is unrepresentative and that the loss in performance can be quantified. A novel finding from this study is the evidence of an unexpected relationship between desorption and inhibition effectiveness. The findings from this study could have great impact on selecting chemicals for high-temperature (HT) applications, even more so in those environmentally sensitive regions where the use of "yellow" (biodegradable) squeeze chemicals is mandatory. Many of these chemicals have been rejected because of their apparent thermal degradation, which has now proved to be unrepresentative. Introduction In November 2005, Statoil began production from the Kristin field. Kristin is a high-pressure/high-temperature (HP/HT) gas/condensate field in the Haltenbanken area of the Norwegian Sea (see Fig. 1). It has the highest reservoir temperature (170°C) and pressure (911 bar) among the fields that Statoil is operating currently. Producing by natural depletion and with the formation water containing in excess of 2,500 ppm of calcium (Ca) and 900 ppm of bicarbonate (see Table 1), downhole CaCO3 scale deposition has been identified as one of the major production-related problems. From the early development phase, an active program to qualify suitable scale-control chemicals has been put in place, and it includes chemicals for squeeze treatment, wellhead continuous injection, and dissolver. For the squeeze chemicals alone, more than 110 products have been tested, 20 of which are considered to be yellow according to environmental classification by the Norwegian authority (Norwegian Petroleum Directorate 2002). Many of these were rejected because of poor performance, but many more of them were discarded because of their apparent thermal degradation at test conditions. This led us to review the current practice in the oil industry for thermal aging of chemicals and the validity of such results in the application in the field. Most of the literature describing the thermal aging of squeeze chemicals was published in 1995 and the years that followed (Collins 1995; Graham et al. 1998, 2000; Audibert and Argillier 1995; Dyer et al. 1999). The enormous interest generated during this period was caused primarily by the Eastern Trough Area Project (ETAP) cluster development that included fields with a maximum downhole temperature of 180°C and a reservoir pressure of 885 bar. The screening technique relied mostly on the aging of chemicals in a sealed Teflon®-lined bomb over a period of 7 to 21 days. The extent of degradation was measured by their relative performance with respect to the fresh products. In these earlier studies, the focus was placed mostly on the effect of carrier-brine composition, pH, and oxygen level. The main degradation mechanisms were considered to be backbone scission and functional group degradation that were caused by hydrolysis and a free radical attack. A good overview of these mechanisms was presented in a recent publication (Kotlar et al. 2006), in which a refined technique for sample preservation and oxygen removal before the thermal-aging step was described. Although this approach was considered to be a reasonable screening technique for the different products, doubt remained whether this was truly representative in the field because the chemical was not confined within a rock matrix. A number of papers did describe thermal aging inside core materials, where both outcrop sandstone (Graham et al. 1997, 2001a) and reservoir (Graham et al. 2001b) plugs were used. Typically, a small core plug was first saturated with the selected chemical and then the core was shut in at high temperature for a period of time. The intended samples (i.e., chemical aged inside the core) were collected afterward for comparative performance-tests. With a short core, the pore volume (PV) would be small, typically 7 mL for a 1-in.-diameter, 3-in.-length core with 18% porosity. If performance tests were to be carried out, these samples would need to be diluted many times. This would be limited to those effluents that had a high-enough concentration [i.e., the first 1 to 15 PV (24 hours) of the post-flush]. This was a short time frame compared to the actual squeeze life in the field. More importantly, the chemical that came out from the core during this period would have been trapped, more so than if they had been adsorbed. The degradation mechanism of the chemical molecules in a physically trapped environment was obviously quite different from that being hindered by a surface-binding interaction. Although yielding some results, such an approach would overlook the most critical part of the degradation process for a squeeze chemical (i.e., the combined effect of thermal aging and the surface-retention mechanism). It is this combined effect on which the current study focuses.
Injectivity Decline in Water Injection Wells: An Offshore Gulf of Mexico Case Study Mukul M. Sharma, SPE and Shutong Pang, The University of Texas at Austin, Kjell Erik Wennberg, SPE, IKU Petroleum Research, Lee Morgenthaler, SPE, Shell Oil Co. Abstract Injectivity decline in water injection wells can have a large impact on the economic feasibility of offshore water disposal operations. A case study is presented for an offshore Gulf of Mexico water injection project. Data are presented for five typical offshore wells for which a rapid decline in injectivity was observed due to water injection. The wells were successfully acidized every few months over a period of two years. An analysis of the data indicates that in injection wells that are not fractured, such declines in injectivity may be expected even for relatively clean injection water. A comparison of the different completion types indicates that both open hole and perforated completions would have yielded similar results. Cleaner water would have improved the situation but at a substantial cost. Fracturing the injection wells appears to be the only plausible way of substantially increasing the half life of such injectors. In cases where reservoir conditions dictate that the wells not be fractured, the economics of periodic stimulation versus the cost of installing surface facilities for cleaning up the water should be evaluated using models for injectivity decline. "What if" simulations conducted to study the impact of different process parameters such as injected particle size and concentration, injection rate and reservoir properties were found to be a useful tool in specifying water quality requirements. Introduction The injection of water for pressure maintenance and waterflooding applications or the disposal of produced water are becoming increasing important issues in the management of produced fluids. Most mature oil and gas producing regions of the world currently have a ratio of produced water volume to produced hydrocarbon volume in excess of 25 to 1. This indicates that large volumes of produced water need to be dealt with for disposal purposes. In offshore operations, the injection of sea water for pressure maintenance or for waterflooding is becoming increasingly common. For these reasons, it is imperative to have reliable models to predict the behavior of water injection wells. Barkman and Davidson provided a method for estimating the half life of an injection well when the reservoir properties (kh) and water quality are specified. This method has been extensively applied to evaluate injector performance. Estimates of injector half life based on this model provide us with an order of magnitude estimate of injector half life. More recent models by Van Velzen and Van Oort provide us with a basis for using core data in predicting injector half lives. Models for injectivity decline for injection wells with various types of completions such as perforated wells, gravel packed wells and fractured wells have been provided by Pang and Sharma. These models allow us to either use core flow test data or empirically derived filtration parameters that can be used in estimating the performance of injectors. In this paper, we present a case study of the application of these models to 5 water injection wells in an offshore environment. The results of the simulation study clearly point to the usefulness of conducting such simulation studies to obtain the optimal water quality requirements which dictate the surface facilities required for maintaining specified injection rates. The case study presents a unique data set for unfractured injection wells in which the performance of the injectors has been carefully monitored over the duration of the project. The quality of the injection water and the procedures taken to treat the water have also been extensively documented. Our main focus in this paper is the injectivity decline that is caused by injected fines and their impact on injector performance. Water Injection Project History The goals of this water injection project were to maintain reservoir pressure in the target sand. The target sand is completely unconsolidated and only slightly compacted. Five injectors were drilled and completed below the oil - water contact in the target sand. Each well has a permeability height (kh) product in excess of 53,000 mD ft. (Table 1). P. 341^
In several HT/HP production environments severe downhole carbonate scale is often anticipated.Moreover, the high temperature means that reaction kinetics are very rapid and therefore the propensity for scale formation remains high even at moderate levels of oversaturation. However, a number of limitations are recognised when assessing the scale risks associated with such production conditions. This includes; uncertainties regarding the initial FW composition, accuracy of scale prediction tools and the application of conventional laboratory test procedures under these conditions. This paper describes the use of a novel HT/HP stirred reactor test rig (400F & 5,000 psi) designed to conduct in situ scaling experiments and allow equilibrium conditions to be established. The equipment is specially designed for the extraction and stabilisation of samples at or near tested conditions allowing the equilibrium brine composition to be determined under more representative HT/HP conditions.Initial results presented in this paper describe the commissioning and validation of the experimental design including the use of tracers to ensure effective transfer and collection of fluids from the reaction vessel. Results are then presented to determine the equilibrium saturation state of a particular field brine starting from the supplied water composition. In summary equilibrium saturation tests conducted at 340F and pressures between 200 psi and 5,000 psi showed significant quantities of carbonate scale (both barium and calcium carbonate) precipitating from solution, indicating a potential uncertainty in the original brine composition. In summary, the data generated allows equilibrium saturation levels to be determined under HT/HP conditions allowing uncertainties in the water composition to be assessed. The determined saturation levels are also directly correlated with dynamic tube blocking tests and scale prediction tools.The data can therefore be used to further tune predictive modelling capabilities under these more extreme (HT/HP and high salinity) conditions. Introduction The development of HP/HT gas production fields in the North Sea has brought about a number of important oilfield scale control problems. These fields are often characterised by high salinity brines (TDS>200,000ppm), high temperatures (T>150°C) and downhole pressures>10,000psi.1 In several of these HP/HT fields, severe downhole carbonate scale is anticipated. The supersaturation of calcium carbonate is controlled by a number of variables including temperature, pressure and pH. Carbonate scale formation often occurs due to pressure reductions and the evolution of carbon dioxide from the brine phase. As carbon dioxide is evolved, the solution pH increases (Equation 1) and the solubility with respect to carbonate declines rapidly, leading to precipitation (Equation 2). However, in some cases, if the brine is not already saturated when CO2 is released, it will dissolve in the brine, causing the pH to drop. If the pressure continues to drop when the brine is completely saturated with CO2, then the pH will rise. The solubility of CO2 in the water is controlled by the gas phase composition, temperature and pressure.Equations 1 and 2 For gas production systems however evaporation of water (H2O) represents a further mechanism for carbonate scaling due to increased scaling ion concentrations in the residual brine phase.2,3
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