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 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^
The deepwater Gulf of Mexico is a technically and economically challenging production environment. High rate and ultimate recoveries per well are required to offset high development costs. Stimulation is employed to maintain wells at peak production rates and accelerate reserve recovery. In the complex layered reservoirs of the deepwater Gulf of Mexico stimulation is also necessary to ensure volume recovery. The primary objective of stimulation is to restore impaired well /reservoir connectivity. In complex reservoirs this may be reflected in either a reduction of skin or improvement in apparent permeability height. In poorly consolidated sandstone reservoirs production may become impaired during completion operations by suspended solids, polymer residue, or incompatible fluid systems. During production fines migration, scale deposition, and organic deposits in the near wellbore and sand control system can lead to declining inflow performance. Successful identification of the cause and location of impairment is required for success. The increasing population of subsea wells creates new challenges for intervention. Correct operation of the well post stimulation is also necessary to achieve the desired rate increases without compromising production system performance. The nature of impairment, treatment options, and post treatment production issues often change over the life of the well. Looking back over a decade of experience in this challenging environment yields useful insights as we move into new deepwater provinces.
Summary Big reservoirs in deepwater Gulf of Mexico (GOM) typically produce at world-class rates. The scale of investment is likewise world class. The energy industry's drive to invest in enhanced oil recovery from deepwater basins is sustainable in a world of volatile oil prices and increasing demand for energy. However, project economics will continue to depend on accurate risk assessment, risk-mitigation strategies, and, more fundamentally, progressive deployment of evolving technologies in brownfield deepwater secondary-recovery projects. Details of well geometry and design optimizations may prove to be minor sensitivities in high-cost deepwater developments; however, rig rate has a major impact on economics. The assessment required to minimize the number of injectors and ensure their proper placement logically takes more time than exotic choices of injection patterns. With such major constraints in mind, an optimal design for wells and materials has to take precedence. Accepting this as a given, additional, more common challenges would then follow. The waterflood-study team for the deepwater Ursa/Princess field in the GOM has spent appreciable time and effort evaluating various potential challenges affecting the surface and subsurface aspects of the development plan. The design for an optimum injection rate was a bottom-up process starting from the reservoir up to the topsides injection facilities. Reservoir-sweep efficiency and reservoir-pressure distribution logically dictated injection-well designs and injection-pump sizing. Subsurface risks, such as reservoir souring and hydrate formation, dictated materials selection and completions design. This paper addresses the challenges primarily affecting the design of the deepwater subsea-injection wells. In addition to the well cost, several other underlying factors have played an influential role in defining the boundary conditions for the injectors design. Background Industry-wide experience in the execution and the operation of waterflood projects in deepwater environments is relatively limited. With relatively few analogs, the Ursa and Princess fields are set to embark on major facilities expansion and subsea development. The aim is to deliver a high rate of specific-quality water through four subsea-injection wells into a vast and, largely thirsty, reservoir. Ursa and Princess reside 100 miles south/southeast of the Mississippi River mouth in the Mars basin, GOM. The Ursa field was discovered in 1990 and has been on production since 1999. The Princess field was discovered in 2000 and has been producing since December 2003 through a subsea tieback to Ursa. The fields have their main reservoirs in common and are in pressure communication. The working interest in the Ursa and Princess fields are Shell (45--operator), BP (23%), ExxonMobil (16%), and ConocoPhillips (16%). The Yellow reservoir is the main reservoir at both Ursa/Princess and Mars, the other major field in the Mars basin. It is a world-class Upper Miocene turbidite reservoir that stretches across the Mars basin, including the Mars field. This 12,000-acre reservoir is charged with light-oil type, though with slight variations in properties, as indicated by the analysis results of the abundant pressure-volume-temperature measurement samples. Because of limited TLP well availability, the high cost of subsea wells and the limitations of the subsea system to handle large water cuts, the waterflood will use relatively few injectors. The proposed base plan has four water injectors: two into Princess and two into Ursa. Producing wells will include three Princess subsea wells and four Ursa TLP wells. Five TLP wells are to be sidetracked updip or recompleted at a later stage. High injection rates are required to replace voidage and maintain reservoir pressure above bubblepoint. Initial injection rates per well (annual average) of 30 to 40 thousand BWPD are required. This injectivity can only be maintained by creating fractures. With the wide well spacing relative to fracture length, this is not expected to negatively impact sweep efficiency. However, because of the uniqueness of well spacing and reservoir volumes, there is a lack of analog-data points to calibrate the outcomes. Parallel evaluation of the viability of artificial lifting has shown that TLP waterflood producers would benefit from gas lifting. The base plan for waterflood wells thus includes the requirement for gas-lift completions and facilities. The original Operating Health Safety and Environmental (HSE) case for the asset did not include the potential threat of reservoir souring after seawater injection. The well casing and tubular materials, therefore, have limited resistance to sulfide-stress corrosion cracking. This resulted in the need to recomplete the Ursa TLP direct-vertical access (DVA) wells with Shell-qualified tubing. Princess producers already have Shell-qualified C100 sour-resistant casing, and will not require pre-emptive intervention for tubing change out.
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