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Abstract Natural supplies of fresh water are limited while the demand for fresh water is increasing worldwide. Production of fresh water at sea is often achieved through a restricted group of conventional desalination technologies including reverse osmosis and modern versions of distillation. Two methods of unconventional water production, one of which is based on the unique set of resources available at an operating production platform, may provide solutions for provision of potable water and for industrial dewatering of process water. Introduction Fresh water is a dynamic resource produced largely by solar energy and stored in lakes, rivers, disappearing glaciers, and groundwater aquifers. Fresh water can be pumped over large distances to supply farming, industry, and population centers, although where this takes place on a large scale, the cost of infrastructure and energy can be very high. When a center of water use is far from a water source or is completely isolated, water produced on site may often be the only answer. This may be especially true where barging or bulk transport instead of pipeline transport is concerned because of the increasingly high cost of energy. Fresh water production from a more saline source water can be achieved by using two primary mechanisms. First, desalination of local saline water into a fresh water product stream and brine reject stream (Fig. 1). Typical methods for achieving desalination are reverse osmosis (RO), or any membrane-based technology, and distillation (MED, Multi-Effect Distillation; MSF, Multi-Stage Flash), which relies on vaporization and condensation. There are presently a host of hybrid techniques where different methods are used on the same water stream to magnify overall efficiency. The second general method condenses water from humid air, without first having to vaporize it. This is known as water harvesting (Max, 2004) and can be achieved on an economical scale depending on the local environmental conditions. Large scale water harvesting to support military expeditionary activity is currently an area of interest to the U.S. Army, which has developed truck mounted apparatus that produces up to 1,600 gallons per day. Additional methods for producing fresh water include solar humidification, which is a direct analog of the natural hydrologic cycle, and clathrate desalination, which is an industrial analog of desalination that takes place naturally when natural gas hydrate forms in marine sediments. Clathrate desalination (Max, 2006, Max and Pellenbarg, 1999) makes use of the tendency of some gases to form solid compounds in natural ocean water at appropriately low temperature and high pressures. Although uncontrolled clathrate formation in pipelines can lead to very costly and hazardous blockages, formation of clathrates under controlled conditions has the potential for sweetening (removal of hydrogen sulfide) and energy density enhancement (removal of CO2). Primarily, however, clathrate desalination has the potential for desalination of seawater and for industrial dewatering (Max and Osegovic, 2004).
- Water & Waste Management > Water Management > Water Supplies & Services (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract Unwanted hydrate (Clatrhrate) formation is a major flow assurance issue for exploitation of hydrocarbon resources, especially in the more remote and colder environment of offshore deep water. Unwanted hydrate may form as the temperature of extracted gas and oil falls following its removal from its reservoir and the pressure, temperature, and water concentration become suitable for hydrate formation. Preventing unwanted hydrate formation is presently accomplished mainly using inhibitors that retard the nucleation, growth, and agglomeration of hydrate or through the crystallization in petroleum of many crystallites (cold flow). A new approach to preventing the formation of unwanted hydrate is described. In this method, the removal of water from the pipeline system, without which unwanted hydrate cannot form, is the objective. It is not necessary to remove all water; but only to keep the vapor pressure of dissolved water low enough so that unwanted hydrate will neither nucleate nor grow. Water is extracted through the controlled crystallization of hydrate, which extracts dissolved water from the hydrocarbons in an innovative manner. In the proposed method, hydrate is formed on surfaces of a permeable heat exchanger through which the hydrate is dissociated and the water removed. Dynamically forming hydrate on the exterior (pipeline side) and dissociating on the interior side of the porous surface (in a low pressure chamber) allows for collection and removal of water from the pipeline. This eliminates the potential for unwanted hydrate formation of the mixture down stream. More than one water removal stage in a pipeline may be required. The method holds promise to achieve hydrate flow assurance on the seafloor without the use of chemicals or extensive industrial plants at a very low energy cost. Inversion of Unwanted Hydrate Formation Prevention Techniques Spontaneous hydrate formation can lead to blockages of petroleum and gas pipelines. In order for natural gas hydrate to form spontaneously, the pressure and temperature conditions must be within the range of hydrate stability and the limiting reagent (gas in an aqueous system or water in a gaseous system) must be present at super saturation levels. When these conditions occur, there is the possibility that hydrate formation may cause partial or complete blockage that will result in restricted flow or pipeline shut down. As either pressure increases or temperature decreases, hydrate formation potential also increases. Falling temperature will cause hydrate to form, however, even where pressure is decreased substantially. While historically successful, many current methods require adding chemicals to the transport pipeline in proportion to the hydrate formation potential. The potential to form hydrates can be so great as to make conventional inhibition methods impractical, especially as deeper water conditions are entered and longer pipelines are necessary. The focus of flow assurance research has been avoiding or retarding hydrate formation. Currently, the most commonly applied methods to prevent natural gas hydrate formation are inhibition using methanol, a thermodynamic inhibitor, low dose kinetic inhibitors, or glycol drying. Drying the gas helps to prevent hydrate formation because once enough water is removed from the system, the hydrate cannot form. In addition, if any hydrate previously present is exposed to dried fluid, the hydrate may actually dissolve. While glycol is an accepted drying method, it cannot be implemented at the wellhead and its use involves environmental concerns. Insulated pipes have also been put into service in order to maintain temperatures above the hydrate phase boundary. As the production environment gets harsher, the amount of methanol required to avoid hydrate formation may become excessive. As a result, flow assurance prevention is becoming an increasingly important cost factor in opening or maintaining a field in which water cut is increasing.
- Europe > Norway > Norwegian Sea (0.65)
- North America > United States > Texas (0.47)
Abstract Mixing of injected seawater with formation brines may cause scale precipitation at production wells and surface facilities, but does not generally cause significant damage within the formation itself. Indeed, mixing within the reservoir may be beneficial, if the concentration of scaling ions is reduced due to ion stripping as the brine mixture approaches the production well. One potential exception to this is when the availability of produced water for re-injection (PWRI) is insufficient to maintain voidage replacement, and must be supplemented with seawater. Under such circumstances, seawater and formation brine may be completely mixed before injection. This will not lead to a loss of injectivity if scale inhibitor chemicals are appropriately applied to the injected brine stream. However, scale inhibitors are retained by the reservoir rock as they are displaced away from the wellbore, resulting in the inhibitor front propagating more slowly than the saturation front - usually referred to as chemical retardation. As brine is displaced away from the injection well, the upshot is a growing zone of mixed brine with chemical concentration below the threshold required to inhibit the scaling reaction. The question this paper considers that has not been addressed before is whether the ratio of produced water to seawater that is injected, the possibility of treating the injection brine mix with inhibitor, and field specific details such as the location of the injection wells relative to production wells and the aquifer can impact how this zone of unprotected mixed brine is displaced and reacts deep within the reservoir, away from both injection production wells. If the scaling reaction can be limited to a region deep within the reservoir where the volume of rock is large compared with the potential mass of scale that may deposit, then the sulphate ions associated with seawater may be stripped from the brine mixture before the water is produced. Thus, by considered yet straightforward management of the PWRI scheme, it may be possible to protect the production wells from scale damage in a way that is not possible under conventional seawater injection. This hypothesis is tested using conventional reservoir simulators and reaction-transport modelling. Various conditions are considered, including brine reactions, extent of brine displacement through the oil leg or aquifer, as well as management of the PWRI wells. Prediction of scale damage potential at production wells is made for an example field system. Introduction Produced Water Re-Injection (PWRI) is a method for maintaining reservoir pressure and sweeping hydrocarbons towards production wells in which water separated from hydrocarbons at the surface facilities is re-injected into the same or another hydrocarbon bearing formation. Optionally, produced water may be re-injected into a specially selected aquifer. The primary objective is generally to dispose of the produced water in a manner that causes minimum damage to the environment. In addition to the environmental benefits, there are other potential benefits including making cost, space and weight savings through the optimisation of water treatment facilities. The principal disadvantage is that usually the quality of the produced water (in terms of oil-in-water and solids content, etc) is lower than that of other potential sources of injection water, and hence damage to the rock matrix into which the water is being injected has to be considered.
- Europe (1.00)
- North America > United States > Texas (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (0.55)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 21/10 > Forties Field > Forties Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 019 > Block 7/12 > Ula Field > Ula Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > King Lear Area > Block 7/12 > Ula Field > Ula Formation (0.99)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)
Abstract The Bonga field, which is located in deep water off the Nigerian coast, started oil production at the end of 2005. In order to sustain production, seawater injection started from the beginning of the oil production at a rate of 300k bwpd. During the field development it was concluded that seawater injection in Bonga would result in reservoir souring, and that mitigation was necessary. Initially the selected strategy for Bonga seawater injection was to control reservoir souring with biocide and handle low levels of H2S with sour service materials and scavenging facilities topside. The maximum H2S the existing facilities could handle was set at 50 ppm (v). The decision to control reservoir souring with biocide and handle H2S at surface was re-evaluated in 2003, and it was concluded that there would be a risk that the maximum allowable H2S content in the facilities (i.e. 50 ppm(v)) might be exceeded during the life time of the project. Given the positive experience with the injection of nitrate in other seawater floods throughout the industry, nitrate was selected as the mitigation method and injection started directly at the beginning of the waterflood at the end of 2005. As such Bonga is one of the first waterfloods where nitrate is being used to prevent reservoir souring, the main application so far has been to reduce H2S in already sour fields. This paper presents the experience gained with the nitrate injection during the first period of the Bonga waterflood. Issues like logistics and how to ensure nitrate is applied correctly are discussed in more detail. In addition laboratory testing executed to define an appropriate nitrate injection rate under Bonga conditions are also presented. After several months of operation the Minox unit to remove the bulk of the oxygen broke down and oxygen control was done with chemical oxygen scavenger only. With this different mode of operation, the effectiveness of the nitrate as souring mitigation method was expected to be affected. Additional laboratory experiments, also reported in this paper, were performed and did not indicate any issue with respect to the predicted souring. Introduction The Bonga field lies on the continental slope in the southern part of the Niger Delta some 120 km offshore, South West of Warri in Nigeria with water depths ranging from 950 to 1200 m. The main 702 reservoir, which is expected to deliver over half of the recoverable reserves, is comprised of amalgamated turbidite channels. Typical net reservoir thickness is less than 100 ft with sand porosities range from 20 - 37% and multi-Darcy permeabilities. Seawater injection for pressure maintenance and sweep is key to the success of the Bonga development. A total of sixteen wells (nine producers and seven water injectors) were drilled during the Bonga phase 1 drilling campaign. Another twenty-four wells will be drilled in Bonga Main with eight additional "in field opportunity" wells, which started November 2006.All fluids produced are processed on an FPSO situated centrally in the field and oil is directly loaded to tankers. The associated gas is exported through pipelines. Produced water is processed to appropriate standards and disposed of overboard. During the field development it was concluded that Bonga was expected to suffer from reservoir souring and that mitigation would be necessary. Initially the expected H2S content resulting from reservoir souring was not expected to exceed 50 ppm (v) in the gas phase, but when more data became available it was realised that the reservoir souring may be more severe and the final mitigation method included the use of nitrate (Ref. 1). The nitrate injection rate was 45 ppm w/v active nitrate, which was based on field experience only as currently there is no engineering method available to optimise this injection rate.
- Africa > Nigeria > Gulf of Guinea > Niger Delta (0.54)
- North America > United States > Texas (0.47)
- Geology > Mineral (1.00)
- Geology > Sedimentary Geology > Depositional Environment > Marine Environment > Deep Water Marine Environment (0.54)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 050 > Block 34/10 > Gullfaks Field > Statfjord Group (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 050 > Block 34/10 > Gullfaks Field > Lunde Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 050 > Block 34/10 > Gullfaks Field > Lista Formation (0.99)
- (7 more...)
Abstract The incompatibility of injected saline seawater and formation water is the primary cause of scale deposition in offshore developments. Many offshore oilfields are encountering problems with barium sulfate precipitation due to the mixing of sulfate-anion-rich seawater and formation brine with excessive amounts of barium cation. A mechanistic physico-chemical modeling approach is required to predict the amount of scaling to assist operators in making decision regarding scale prevention in oil reservoirs. The predictive model allows various types of flow scenarios to be investigated to reduce the amount of scaling and prevent well damage and eventual loss of well productivities. Three-dimensional field-scale simulations were performed to investigate the flow and transport of barium and sulfate ions and the significance of barium sulfate precipitation in a typical offshore oil reservoir. The reservoir simulator has the modeling capability of multiphase flow, water reaction chemistry and interaction with the rock, and more significantly the species transport equations that include physical dispersion. The reactions were kept simple with barium and sulfate ions as the only reacting species and sodium, chloride, and calcium ions as non-reacting species. Barium sulfate was considered as the only solid precipitate. Simulations were performed to determine sensitivity to dispersion and mixing in the reservoir, to determine how much solid precipitates in the reservoir and in the wellbore, and to estimate how much sulfate needs to be removed from the injected seawater to prevent the formation damage. Introduction Barium sulfate and related scale occurrences are considered serious problems that cause formation damage and loss of productivity near production wellbores. Sulfate scales may result from changes in temperature and/or pressure but the major cause of sulfate scaling is chemical incompatibility between the injected seawater with high sulfate ion concentrations and the formation water, which originally contains high concentrations of barium, calcium, and strontium ions. Yuan and Todd developed a model to predict the sulfate scaling problems due to chemically incompatible waters as well as by temperature and pressure changes. The model is based on solubility prediction and the sulfates' precipitation/dissolution reactions involving sulfate, calcium, barium and strontium ions. The scale predictive model uses an iterative process to meet the competitive coprecipitation of BaSO4, SrSO4, and CaSO4. The results indicated that an increase in temperature lowers the BaSO4 scaling tendency but increases SrSO4 and CaSO4 scaling tendency. The pressure increase universally makes the sulfates more soluble and therefore less prone to scaling. The model developed helps determine the type and maximum quantity of scaling that could form from a solution, but a reservoir simulation model is required to give the scaling rate and distribution in the reservoir. A method of characteristic model was developed by Araque-Martinez and Lake that included kinetics as well as equilibrium reactions to predict the well impairment. This model, however, is appropriate only for near injection wellbore calculations and does not include physical dispersion. Rocha and coworkers have developed a salt precipitation finite element numerical model that is coupled with ion transport equations to predict the amount of precipitates around the wellbore. Although the ion transport equations include the tensor diffusion, the model is developed for single-phase water flow only. Usual chemical treatments may not work for severe cases of BaSO4 scaling and treatment of the seawater to reduce the sulfate content seems more promising in some cases. Desulfurization of the seawater was considered in this paper and simulations were performed to decide how much sulfate would have to be removed from the seawater to prevent precipitation completely.
- Geology > Mineral > Sulfate (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.81)
Abstract The advent of subsea wells, production from ever-deeper waters, and the resulting increase in value of wells and downhole equipment means that more effort is being put into assessing the risks posed by potential scale formation. This is required not only because of the increasing value of the investment that needs to be protected, but also due to the increasing difficulty in accessing wells to treat them. It is becoming widely recognized that an integral part of the scale risk assessment process involves calculating fluid flow in the reservoir. These calculations enable the operator to identify where in the reservoir scale may form, how these zones develop as a function of time, and where they are located relative to the production wells. If scale forms deep within the reservoir, then typically there is no loss of productivity, and indeed the effect is beneficial in that it reduces the scaling potential at the production wells. However, if scale deposition should be expected close to the production wells, then steps should be taken to mitigate any harmful effects. The choice of management strategy will depend on the type and severity of the scaling problem, and the access to the wells requiring protection. A range of flow simulation tools is studied. These vary from standard finite difference reservoir simulators to streamline models designed specifically to track the flow path of injected waters, to more complex fluid flow and chemical reaction models capable of calculating scale precipitation reactions and the subsequent impact on porosity and permeability. Field examples are then given of situations in which these models have been applied, and the implications for scale management of the resulting calculations are discussed. Introduction The deposition of inorganic scales is a flow assurance issue associated primarily with the production of water. The potential extent of scale formation is determined by two principal factors:The temperature, pressure and chemical composition of the brines in the reservoir; The volumes of scaling brines being produced. Scale prediction codes are routinely used to calculate the potential mass and scaling tendency of the produced brines. When account is taken of the expected volumes of produced water, a basic scaling risk may be evaluated. However, an oilfield reservoir under production is a dynamic system, and thus the temperature, the pressure, the chemical composition of the brines, and the volumetric flow rates may all vary from location to location within the reservoir, and will probably also with time. Therefore, the potential for scale formation and damage to productivity will also vary with time. Furthermore, scale precipitation in situ deep within the reservoir may impact the scaling potential at the production wells. Thus, to properly assess the risk of scale damage over a field's life cycle it is necessary to account for the changes in fluid properties in the reservoir with time. Although never perfect, the best estimate of how fluid conditions will vary with location and time may be obtained from the dynamic reservoir simulation model. Reservoir simulations are usually performed to predict and optimise hydrocarbon recovery. Thus, considerable effort is often put into making these calculations as accurate as possible, as important operational decisions relating to the extraction of hydrocarbons may be influenced by the results. However, even the most generalised models may also be used to study, and to an extent to quantify, the scaling risk potential. More complex models may also be used to model the precipitation of scale in situ, allowing for a more accurate prediction of formation damage, and a better understanding of how flow behaviour in the reservoir affects the scaling risk at the production wells. This paper briefly outlines the relevant mechanisms of scale formation, and then discusses the three most common types of reservoir simulation model used to quantify scale risk, what they can and cannot be used to calculate, and what are their principal advantages and disadvantages.
- North America > United States > Texas (0.47)
- Europe > Norway > Norwegian Sea (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (0.34)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Moray Firth Basin > Witch Ground Graben > P.213 > Block 16/26a > Brae Field > Alba Field > Caran Sandstone Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Moray Firth Basin > Witch Ground Graben > P.213 > Block 16/26a > Brae Field > Alba Field > Alba Sandstone Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Fladen Ground Spur > Witch Ground Graben > P.213 > Block 16/26a > Brae Field > Alba Field > Caran Sandstone Formation (0.99)
- (2 more...)
Abstract This paper summarizes the activities in introducing biodegradable synthetic based mud systems in order to overcome ecological concerns like site contamination and heavy environmental impacts caused by the discharge of diesel/mineral oil contaminated drill cuttings during offshore drilling operations. Based on an extensive literature study the biodegradation scenario of the sea is derived, with special attention to the elimination potential on the seafloor. Factors affecting biodegradation like the aqueous medium, bacterial community und number, light intensity, sample concentration, etc. are evaluated for one specific synthetic. However, this data show potential to be of general relevance. Generally, the sea can be divided into three different zones. Two aerobic zones, i.e. photic zone at the surface and the water column followed by an anaerobic zone on the seafloor where definitely most of the biodegradation work has to be accomplished because the residence time of cuttings in the first two zones is rather short. These elimination scenarios are compared to the currently performed testing practice. Most of the today performed OECD tests use technology adopted from waste water purification plants, which obviously represent completely different systems compared to the anaerobic seafloor. Molecules that contain an oxygen-carbon-oxygen bonding within their structure, like acetals and esters, exhibit a distinct advantage over hydrocarbon types like olefins and paraffins, because this specific bonding represents a predetermined breakpoint resulting in an advanced elimination. The pre-determined breakpoint leads to an efficient cleavage of the molecule resulting in much smaller, water soluble and easily degradable material. Under the anaerobic conditions prevailing on the seafloor, where oxidation can not contribute to the overall elimination of organic matter, the incorporation of this pre-determined breakpoint is the key to success in mastering the complex requirements of the drilling industry today, both in performance as well as ecological respects. Introduction With the occurrence of the offshore exploration activities the interest of the authorities increased in order to minimise the environmental impacts. The massive introduction of invert-emulsion muds based on diesel resulted in heavy environmental damages triggering the special reason for this essential interest (Fig. 1). The fact that diesel-oil was substituted by less toxic so-called clean-oil (< 0,5% aromatic compounds) could not significantly change or solve the problem. Up to now 15 year old cuttings sludges based on diesel and/or clean oil can be detected on the seafloor. These sludges, based on the molecular structure of their base oil, could not be degraded and therefore spread over the seafloor resulting in close to 8000 km of contaminated seafloor in the North Sea in 1990. It is common sense that hydrocarbons are generally degradable under aerobic conditions but there is also an unanimous worldwide accepted opinion that hydrocarbons are stable under the anoxic conditions prevailing on the seafloor. This fact, however, represents the basis of the entire petroleum industry, where hydrocarbons, matured, trapped and stored for millions of years under anoxic conditions have been the primary target of all our activities. The first attempts to drill with naturally occuring, biodegradable oils are stemming back into the 70-ies. But these glycerine-esters were much too viscous and the breakthrough was achieved by the optimization of the esters through cuts of natural fatty acids with a synthetically branched alcohol. P. 517^
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract This paper presents novel organic crosslinkers that extend the temperature limitations of currently available polymer gel systems. These organic crosslinkers have application in steam injection, geothermal and high temperature oil and gas wells. One crosslinker exhibits a gelation time of several days at 350 F. Long-term stability has been verified for at least one year at 300 F. Some novel organic crosslinkers for low and medium temperature applications are also presented. Introduction Polymer gels have been applied in oil and gas wells for many years to control the flow of fluids within the reservoir. They are inexpensive, simple to apply, versatile in their application and readily available. One major limitation of some gel systems currently in use is that the gelation reactions cannot be delayed for more than several minutes at elevated temperatures. When retardants are used to alleviate this problem, the gel typically weakens and loses some of its gel strength or becomes completely unstable. High Temperature Uses for Gels Several of the organic crosslinkers presented in this paper have application in steam injection wells, geothermal wells and in oil and gas wells where high reservoir temperatures have historically limited the use of polymer gels. Steam Injectors. Steam injection is beneficial to the production of oil in many reservoirs and in particular, to heavy oil reservoirs, by reducing oil viscosities and removing tarry and paraffin deposits. However, due to heterogeneity and to the fact that steam rises to the top of injected zones because of its low density, steam channels can develop leaving potentially productive intervals unswept. Polymer gels and foaming agents have been used to reduce flow through these channels. The temperature in these steam channels can be as high as 500 F which increases the difficulty in forming an in-depth stable foam or gel. Geothermal Wells. Steam and hot water production from geothermal wells are economical sources of energy for the generation of electricity. This production is often accompanied by high concentrations of salts and undesirable gases. Condensate is generally re-injected into the geothermal reservoir and can sometimes detrimentally affect nearby producing well temperatures. Temperatures in these wells could be as high as 600 F. At this time, we do not have a time-delayed gel for these extreme temperatures; however, successful treatments should be possible below 400 F. High Temperature Oil and Gas Wells. Low temperature reservoirs have been successfully treated with current polymer gel technology. However, there is a need to extend these gel treatments to higher temperature formations because of the increasing depths of commercially productive reservoirs. Temperatures of some oil and gas bearing reservoirs can exceed 400 F. Most reservoirs have problems with channeling during primary and enhanced production, but in higher temperature reservoirs, the problem is more difficult to solve by the use of polymer gel treatments. Polymer instability, rapid gelation and improper placement can result in treatment failures. Definition of Temperature Ranges The following definitions are used in this paper to reflect applicable ranges for currently available technology: P. 361^
- North America > United States > Texas (0.46)
- North America > United States > California (0.28)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Downhole chemical treatments and fluid compatibility (1.00)