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This paper provides development of a novel nanoparticle-based chemical treatment composition for its potential use a loss circulation material. The novel loss circulation material is based on a delayed activation chemistry to gel up an environmentally friendly nanomaterial based dispersion. The chemical treatment composition comprises of two major components viz. nanoparticle based dispersion and a chemical activator. A major advantage of the activator used to gel up nanoparticle-based dispersion is its ability to place the treatment composition in to the target zone before the nanoparticle based dispersion gels up thus avoiding premature setting of the treatment fluid. The newly developed system can be used effectively up to 300°F. The gelation times were evaluated at different temperatures up to 300°F. The effects of pH and different concentration of activators on gelation times of the new treatment fluid has also been studied. The effectiveness of the newly developed composition as a loss circulation treatment was also evaluated by performing permeability plugging tests to test the plugging capacity of this novel system. The novelty of the newly developed treatment composition is to have a controllable gelation time under a variety of downhole conditions to allow accurate placement of the treatment fluid inside the wellbore without premature setting of the fluid. It was shown that the gelation time of the treatment composition could be controlled by adjusting the concentration of the activator. The system gives a predictable and controllable pumping time, ranging from a few minutes to several hours at over a wide range of temperatures. This is an important advantage of as it allows the treatment composition to remain pumpable for sufficient time for placement and develops the network structure that leads to gelation, over a predictable period of time. The set gel, which appears as a crystalline solid, could remain homogenous and stay in place thereby preventing loss circulation.

Organic precipitation during the production of hydrocarbons has proven to be a production assurance problem experienced in the majority of oil and gas fields throughout the world. Paraffin and asphaltene deposition occurs in several areas of the production system including: the reservoir, wellbore components including the perforation face and production tubing, surface components such as chokes and on flowlines, and also in production equipment downstream. In an effort to maintain optimum production, removal of existing restrictions is essential, just as minimizing the deposition of same. There is no universally effective treatment for organic deposition. Proper identification of the deposit, design and implementation of the treatment is essential to the cost effective production of oil and gas wells experiencing the problem. The most common methods of removal include: mechanical means, chemicals of various types, heat techniques and micro-organisms. This paper analyzes the results of a chemical treatment exercise executed in the Southwest Soldado Oil Field, an offshore asset owned by the Petroleum Company of Trinidad and Tobago Limited (Petrotrin). A paraffin dispersant-asphaltene inhibitor was applied as a method of cost-effectively optimizing production, in a field within which organic precipitation is inescapable as a result of the crude's nature coupled with conditions necessary for deposition. Successful application of this treatment in eight (8) flowing wells and seven (7) flowline segments resulted in increased production levels within the field, despite the production constraints experienced within the field at the time. As a result of this success, apart from expansion of the exercise and treatment on an annual basis, continuous chemical treatment systems were introduced to the field, as a means of minimizing deposition on flowlines and in flowing and PCP wells.

Bamboo field is located in block 2A Muglad Basin covers an area of 144 Square km. It consists of multi block, multi-layered under-saturated sandstone reservoir of late Cretaceous ages barried at depth ranging from 1000 m to 1700 m with crude oil viscosity ranges from 70 cp to 3000 cp. The total Field STOIIP and Recovery Factor (RF) are currently estimated at around 506MMSTB and 18% respectively through primary depletion. Up to date; the field had recovered more than 75% of the EUR. The field initially produced around 20,000 STB/Day with early water breakthrough and very minimal gas production rate until today. However the production rate declined rapidly when the water production rate increased. Major factors that contributed to this problem are possibly due to the fingering and water conning. Currently the field is producing around 8000 STB/Day with water cut around 80% and keeps increasing. Schemes in enhancing and prolonging the already decline production and diminishing reserves strategically call for timely implementation of Enhanced Oil Recovery (EOR) process. Among various Enhanced Oil Recovery (EOR) process and techniques, Bamboo reservoirs appear especially amenable to thermal injection process. But Sudapet, ITB and PERTAMINA (an especial study) came up with different solution which is Huff and Buff of Chemical EOR, This proved to be one of the practical, promising and potential options in enhancing the recovery factor in Bamboo Field. This paper will discuss the lab study scope, includes the core sample, fluid sample, phase behaviour test, spontaneous Imbibition Test, Compatibility test, Viscosity Mixture and core flood, well selection analysis as well as the implementation of SEMAR as pilot project in Bamboo Oil Field. After implementation of the pilot as Huff and Puff in three wells the results show that about 18,000 STB of oil gained from adjacent wells, which indicate that SEMAR is very interesting to be evaluated for further steps in chemical EOR implementation for continuous Injection.

This is the final installment in a series of three papers examining iron mineralogy and its effect on surfactant adsorption in reservoir and outcrop rock samples. The goal of these studies is to establish best practices for obtaining surfactant adsorption values representative of those in a reduced oil reservoir, despite performing experiments in an oxidizing laboratory atmosphere. This article follows two others examining the abundance and form of iron in the reservoir and in core samples (Part I: Levitt et al., 2015), and a proposed core restoration technique utilizing iron-reducing bacteria (Part II: Harris et al., 2015). In this Part III, chemical reduction methods are examined. Surfactant retention is a leading uncertainty in economic forecasting of chemical EOR, in large part due to the order-of-magnitude effects of artifacts such as improper core preservation. The industry standard is to (a) limit atmospheric contact of cores to the extent feasible, and (b) when necessary, reduce oxidized cores using strong reducing agents such as sodium dithionite, along with buffering and chelating agents such as sodium bicarbonate and EDTA or sodium citrate. However few studies have been performed to determine whether such invasive treatments are necessary, or what unintended effects the use of such reactive chemicals may have. The most striking conclusion from these studies is the lack of clear evidence of any advantage of electrochemical reduction versus a simpler treatment with chelators such as sodium citrate or EDTA. Wang (1993) suggests that oxidation of reservoir cores leads to higher surfactant adsorption due to the reduction of clays, which yields a more negative surface charge. Static experiments with montmorillonite clay, as well as an oxidized outcrop containing significant clay and iron content, illustrate that rinsing with non-reducing agents such as sodium bicarbonate, EDTA, or sodium citrate can lower adsorption as much as a strong reducing agent such as sodium dithionite. In the case of montmorillonite, cation exchange appears to be the mechanism by which adsorption is lowered, and so NaCl alone is sufficient to lower adsorption to near-zero values. For the iron- and clay-containing outcrop material, initial measurements indicating "adsorption" far in excess of a dense bilayer were due in fact to the precipitation of sulfonate surfactant with calcium, which eluded from the dissolution of small amounts of anhydrite. An alkyl alkoxy sulfonate surfactant showed higher calcium tolerance, and did not yield "multilayer" adsorption when equilibrated with the anhydrite-containing core sample. While treatment with a citrate-bicarbonate-dithionite solution does indeed lower adsorption several-fold further, solutions of either sodium bicarbonate or EDTA are at least as effective, and sodium citrate is almost as effective. These non-reductive treatments remove small amounts (~0.1% – ~0.2% of rock mass) of Fe and Al, and fines are invariably apparent in treatment fluids, both of which suggest removal of small amounts of trivalent Fe/Al colloids. Wang (1993) suggests reduction or removal of trivalent iron from clay surfaces as a possible mechanism of lowered adsorption under electrochemically reducing conditions. These results suggest that removal of trivalent cations, with concomitant lowering of anionic surfactant adsorption, is possible with non-reductive chelators such as sodium citrate or sodium EDTA. Sodium bicarbonate is equally effective at lowering adsorption, but does not result in elution of Fe or Al, indicating that these are likely reprecipitated. PIPES buffer, which is used in biological applications for its low propensity to form ligands, lowers adsorption as much and no more than a 10% NaCl rinse, suggesting only anhydrite removal and possibly cation exchange with clays occurs. While these results suggest that non-reductive means may be used to remove artifacts introduced by core oxidation, they come with an important caveat: even rinsing with a brine solution can result in significant alteration of mineralogy. The use of chelating agents will invariably result in dissolution of any soluble minerals present such as gypsum or anhydrite, which can be an important contributor to surfactant (in particular ABS) consumption. In cases where iron removal is necessary due to polymer degradation issues, PIPES buffer is proposed for use as an alternative to bicarbonate, the latter having a greater tendency for ligand formation. The combination of borohydride and bisulfite is suggested as an alternative to dithionite as a reducing agent, resulting in more complete iron removal under some conditions, and anecdotally less tendency for polymer degradation upon subsequent oxidation, though both of these claims should be verified.

Recycling produced water for re-use in gas and oil fields for hydraulic fracturing and re-injection to maintain reservoir pressure is becoming increasingly important due to the scarcity of this natural resource. This is especially the case when these activities are not near a readily available source of ‘free water’ such as seawater or an aquifer. This paper considers ways to use water management to lower operational expenditures OPEX by eliminating freshwater sourcing, transportation, storage and its treatment as well as the storage, transportation, treatment and disposal of produced or flow-back water. The water management approach enables operators to re-use produced waters in hydraulic fracturing fluids. Pretreatment testing and analysis characterizes the chemistry of the water to ensure an effective fracturing fluid design and to determine the appropriate water treatment solution for every application. By using a comprehensive water treatment suite of technologies, we demonstrate that virtually any oilfield water can be treated. Posttreatment testing confirms the water meets the customer's specific requirements. Integrating water management service technical expertise with water chemistry and chemical treatments maximizes hydrocarbon production, minimizes reservoir damage, and reduces the costs of freshwater sourcing by as much as 90%. The techniques also offer real routes for oil operators to meet regulatory requirements, mitigating environmental impact.

Recycling produced water for re-use in gas and oil fields for hydraulic fracturing and re-injection to maintain reservoir pressure is becoming increasingly important due to the scarcity of this natural resource. This is especially the case when these activities are not near a readily available source of ‘free water’ such as seawater or an aquifer. We explore ways to use water management to lower Operational Expenditure OPEX overall by eliminating fresh water sourcing, transportation, storage and its treatment as well as the storage, transportation, treatment and disposal of produced or flow-back water. The water management approach enables operators to re-use produced waters in hydraulic fracturing fluids. Pre-treatment testing and analysis characterizes the chemistry of the water to ensure an effective fracturing fluid design and to determine the appropriate water treatment solution for every application. By using a comprehensive water treatment suite of technologies, we demonstrate that virtually any oilfield water can be treated. Post-treatment testing confirms the water meets the customer's specific requirements. Integrating water management service technical expertise with water chemistry and chemical treatments maximizes hydrocarbon production, minimizes reservoir damage, and reduces the costs of fresh water sourcing by as much as 90%. The techniques also offer real routes for oil operators to meet regulatory requirements, mitigating environmental impact.

A successful trial of the Gas Well Stimulant WS-1200 was recently completed on a gas well with high Condensate-Gas Ratio (CGR) and producing below the dew point to treat fluid blockage in Saudi Arabia. The treatment consisted of pumping from a surface 2 wt% active solution in common organic solvents that solubilizes and/or displaces the brine and condensate that are present in the near wellbore region of a fluid blocked well. After bullheading the treatment into the well, it was chased with two equivalents of nitrogen gas. The well was shut-in over night for the treatment to react and then the well was opened to flow and clean out. A test separator was connected to measure the flow at surface and compare the flow after the treatment. Several days were required after opening the well to back-produce the solvents and evaluate the well through the test separator until stabilization was acquired. The well was put back online and continued monitoring production for several months. Just prior to injection of the chemical treatment, the well was producing ~1.5 MMSCFD and ~275 BOD. Within five days of concluding the injection, the well was producing ~2.7 MMSCFD and ~1,000 BOD and in an increasing trend. The well was left in production with only the wellhead temperature (WHT) and wellhead pressure (WHP) being monitored on an ongoing basis. After three months of production, the well rate was again measured through a separator at similar conditions and found to be ~2.85 MMSCFD and ~1,152 BOD, a sustained improvement of 83% in gas production and a 313% improvement in oil production. In light of initial encouraging results, similar chemical treatments are planned in other sandstone reservoirs with similar problems.

Abstract Productivity of gas-condensate wells decrease as bottomhole pressure drops below dew point and condensate starts accumulating surrounding the wellbore. The deliverability of gas-condensate reservoirs is controlled by transport properties, mainly capillary pressure and relative permeabilities between the fluids in a pore-scale. When condensate drops out in the reservoir, the relative permeability to gas decreases and affects the flow rate. The productivity of gas-condensate reservoirs can be effectively enhanced by creating hydraulic fractures to reduce draw-down pressure near wellbore. This helps maintaining the flowing bottom-hole pressure above dew point and consequently delays condensate accumulation. In rich gas reservoirs where condensate to gas ratio (CGR) is high, it becomes challenging to keep the pressure above the dew point. Other approach to enhance relative permeability to gas is by altering the system wettability and making it preferential to gas flow. Recently, a chemical treatment was developed by 3M company (3M) in collaboration with the University of Texas at Austin (UT) to remove condensate banking effect. The treatment fluid was tested in the United States and showed promising results. In this work, Saudi Aramco participated with 3M and the University of Texas Austin to implement a field trial of the chemical treatment on one of Saudi Arabian gas wells that declined in productivity over its production life due to sever condensate banking. The treatment aimed to enhance the relative permeability of the least-wetting phase of the fluids in-place and reduce the effect of condensate-banking was successfully pumped in the candidate well. The initial results of the field implementation demonstrated a significant improvement of gas flow rate and a simultaneous increase in the flowing wellhead pressure. Key results were consolidated with a Pressure Build-up Test conducted six months later, proving effectiveness of chemical treatment on reducing condensate saturation, increasing relative permeabilities to gas, and modifying wetting conditions to make it preferential to gas, which significantly enhances recovery from such high CGR gas reservoirs. Introduction Gas-condensate fluids are mixtures of hydrocarbon molecules that are initially present as a gaseous phase at reservoir conditions. During the depletion of the reservoir fluids as the reservoir pressure falls below the dew point pressure, the liquid phase comes out of the single phase hydrocarbon. When the pressure crosses the dew point pressure, the bonding between the light components and heavy components of the single phase fluid in the reservoir are weakened causing a split between the light and heavy components (Ahmed, 2000). The result of the split enhances the bonding among the heavy components and makes it stronger forming condensate. The condensate thereby keeps accumulating until a maximum liquid dropout is reached. The condensate accumulation takes long time before it reaches the critical condensate saturation allowing the fluid movement. During this time, reduction in gas flow is sensed and is directly reflected on the production performance.

Sand production presents a major challenge for many operators in unconsolidated formations. The production of formation sand and fines can cause erosion damage to surface and downhole equipment, resulting in major well intervention and sand disposal costs. This has a significant negative impact on hydrocarbon production and revenue in terms of decline in production and downtime for intervention. The oil industry encounters severe costs each year attempting to control sand production by methods such as gravel packing, frack packing, and screen-only completions, which are designed to inhibit the movement of sand from the formation into the wellbore. Resin consolidation is an alternative cost-effective solution to mechanical methods. Resin consolidation increases the cohesion forces between sand grains, resulting in high-strength consolidation of the formation grains while maintaining most of the permeability of the rock. Historically, chemical treatments for sand control have been solvent-based, applicable only in relatively short intervals, and with low flash points; as a result, they can be challenging to manage in an offshore environment and difficult to register for use in the North Sea. Recent developments in aqueous-based resin (ABR) technology have resulted in resin consolidation that provides additional benefits, such as improved health, safety, and environmental (HSE) characteristics, and also allow longer heterogeneous intervals to be treated. This paper discusses the application of an ABR treatment that was used successfully for the first time in the North Sea for Shell. Job planning, laboratory analysis, execution, and well performance are discussed. Subsequent sand monitoring has shown that the sand production in this well decreased by more than 80%, with no impairment to oil production.

The chemical treatment using surfactants/solvents can mitigate the liquid block by wettibility alteration in gas/condensate wells. Recently, its application has been extended from wettibility change in matrix to wettibility alteration in propant in hydraulic fractures and tested in field trials. The leak-off of working fluids into matrix may mitigate the liquid block in the matrix adjacent fracture walls unintentionally. However, it is not clear yet whether the mitigation in matrix from leak-off is significant, compared with the mitigation in the fracture propant, and how this may affect the job design. The experimental setup and associated results was for assessment of the treatment in fracture propant only. In the lab, the leak-off will not affect the flow in fracture since hydrocarbon is injected along the fracture to simulate the production. In reality, the hydrocarbon produce passing through the matrix blocks along fracture. And all previous modeling study and job design has ignored the leak-off. This work shows by simulation of a generic case how the leak-off may affect the design and outcome of the treatment. This work clarifies several important design concerns for the chemical treatment in hydraulic fractured reservoir, which may be extended to natural fractured reservoir as well. This will affect the optimal treatment volume, prediction of outcome and economic evaluation. The leak off may bring little extra benefit from the removal of the block in matrix along fracture walls. But such extra benefit is not significant compared with that in the fracture propant. Due to leak-off, the treatment volume based on fracture volume is not adequate and the associated outcome prediction is optimistic. There is an optimal treatment distance along with fracture that had not been identified in previous study. There is not need to treat the fracture at its full length. Just the opposite, with leak off accounted for the attempt to treat the whole fracture will cost huge volume of working fluid and lead to extra liquid damage. The unintentional matrix treatment due to leak off will cost much more working fluid than the fracture treatment. Therefore, it is necessary to optimize the treatment volume during the job design.

The Bantayan field, located on the northeast flank of the South Sumatra basin, was delineated by surface geological studies in the late 1920s as a narrow northwest trending anticlinal structure bisected by numerous northeast trending transbasinal normal faults. In 1932, a discovery well encountered productive upper Talang Akar sandstones which yielded 800 BOPD of paraffinic based crude with a pore point of 115 degrees F. Until year of 1982, only 12 delineation wells were drilled, from which 12 potentially productive sandstone units were obtained within a structural area of 27 sq km. Further evaluation from other new 8-well, it was found that this reservoir system is considered a complex system. In the Bentayan Field, the hydrocarbon oil is deposited in the Talang Akar depositional complex, with the best overall reservoir quality which is relatively thick and well-connected, fine-to coarse-grained, and cross-bedded fluvial sandstones3). Oil properties of this reservoir currently have oil gravity of 17° API and viscosity of 82.2 cp1) at the reservoir temperature. Based on the above oil properties, Bentayan field is considered as a heavy oil reservoir, and so far only 14% of Bentayan oil reserve has been produced. Since 80 years of the discovery, reservoir pressure of Bentayan field has declined from 1696 psi to about 1035 psi, and oil production has also declined significantly. In order improve the oil production, water injection has been implementing to several wells throughout the field, however the oil production is still declining. To reduce viscosity of the oil in the reservoir, application of steam huff n puff could not work very well for improving oil production in this field. This could be caused by high reservoir pressure and also by depth of the reservoir. Since this field is considered as a mature field where all production wells have been producing with high water cut, all conventional efforts to improve oil production would be difficult to success. Implementing chemical EOR, in this case, is the best way to increase oil production. However, the selected chemical must be able to lower the oil viscosity, lower IFT and alter the oil wettability. In this case, a special chemical treatment (SEMAR) had been implemented in this field using huff n puff technique. Since, the reservoir is under strong water drive, the injection of SEMAR can also improve oil production of other surrounding wells nearby. These phenomena are very interesting to be evaluated for further steps in fullfield chemical EOR implementation.

Abstract The chemical treatment (mixture of solvents and a surfactant) to mitigate liquid block (condensate and or water) in gas or condensate well has been tested in the field and shows promising prospects as a long term solution. The injected solvents remaining in the formation after the treatment may reduce condensate production significantly when production resumes. It is therefore of utmost concern to predict correctly how soon the solvents injected will flow back into the well and in which phase will the solvents flow back. A three-phase flash is needed to model the phase behavior and partitioning that occurs during the injection and flow back of treatment solutions. All previous modeling studies were conducted using a simulator with a two-phase flash. To date, the compositional effects of solvents and chase gas during the injection and flow back period have not been understood and modeled adequately. Initial efforts to use UTCOMP with its three-phase flash option to simulate this process were not successful due to the problems with inconsistent phase labeling. A general composition-dependent relative permeability model was developed and makes it unnecessary to identify phases. The molar Gibbs free energy was used as measure of phase composition and as interpolation parameter for relative permeability model. This model was implemented in UTCOMP. The updated simulator simulated the same problem successfully. The correct modeling of the phase behavior makes is possible to a correct projection of the solvents flow back period during the design of chemical treatment. This also makes it possible to evaluate the impact of different solvents and chase gases on the flow back period of solvents. Two groups of eligible solvents along with four kinds of chase gas option (no chase gas, N2, CO2, CH4) were evaluated using a field case. It shows that heavy component of treatment solution flows back significantly from aqueous phase in contrast to previous results from 2-phase flash that heavy components of solvents flows back in oil phase. Light components presents in all three phases in contrast to previous results from 2-phase flash that light solvents flows back only in gas phase. More insight was gained regarding the eligibility of solvents, chase gas, and their combinations. Introduction Li and Firoozabadi (2000) proposed an approach for stimulating gas condensate wells by changing the rock wettability towards non-liquid wetting in the near well-bore region. Kumar et al. (2006) reported improvement in gas and condensate relative permeability when Berea and reservoir sand stone cores were treated using a non-ionic surfactant. Bang et al. (2007) did extensive experiments for sandstone with a variety of new solvents containing a fluorocarbon polymeric surfactant. These eligible solvents included ethanol, isopropanol (IPA), 2-Butoxyethanol (2-BE) and propylene glycol (PG). Ahmadi et al. (2010) reported successful wettability alteration in Texas Cream limestone and Silurian Dolomite cores. Effective solvent mixture was developed for delivering fluorinated chemical to the rock surface. Enhancement in measured gas and condensate relative permeability after treatment was considered to evaluate the effective of different treatments.

Offshore wells, especially deepwater completions, are usually completed with semisubmersible rigs. These use subsea trees, and workovers require moving a costly rig to the location. Solving problems remotely—with an interventionless method—provides huge savings and fewer risks. This paper focuses on the first global installation of a gravel pack system that allowed continuous pay zone chemical treatment pumping without interrupting production. For wells with issues such as barium and calcium sulfates causing obstruction at the sand control screen base pipe holes, this system allowed pumping of scale inhibitors (or any other chemical treatment) to the end of the horizontal well (toe) or to other parts of open- or cased-hole sections without needing to stop production. For this first installation, the system incorporated zonal isolation with feedthrough capabilities using reactive element packer and multiple injection nipples technology, taking advantage of a long shale segment to divide the well in two parts. In general, the number of injection nodes with the same pumping line could vary from well to well. However, at this deepwater installation offshore Brazil, the system was designed to allow continuous pumping of chemicals through only one small-diameter down into a horizontal open hole, to inside the sand control screens at two separate sections of the well, one at the toe and another above the reactive element packer. The system allowed for screen assembly installation and gravel pack pumping in one trip. A reconnect anchor seal assembly was designed and used to deliver a continuality of the flowline conduit from the gravel pack assembly to the upper string assembly. It also incorporated a cost-effective, high-flow liner system for the conduit/injection mandrel protection and a special feedthrough quick connector to simplify certain steps in the assembly. This allowed for torque and traction transmission in open-hole deployment. This paper will describe the implementation and installation of this new system.

In gas condensate reservoirs, considerable productivity loss occurs after the pressure near the production wells drops below the dew point of the hydrocarbon fluids. Over the years, several methods have been proposed to restore gas production rates after a decline in well productivity owing to condensate and/or water blocking. These methods such as gas recycling, hydraulic fracturing and solvent injection have shown to restore the production on a temporary basis only. Altering the wettability of reservoir rock using fluoro-chemical treatments has proved to be a viable and permanent solution to this problem. The selection of these treatments from a large pool of potentially effective chemicals requires extensive laboratory testing which requires time and money. In this paper, we present data that correlates changes in wettability with improvements in relative permeability. Imbibition, contact angle and X-ray photoelectron spectroscopy (XPS) tests along with coreflood results are used to characterize wettability changes. XPS tests, drop tests and core flood experiments were conducted and correlated with each other. It is shown that XPS analysis and imbibition tests provide a quantitative measure of chemical adsorption and surface modification, but only a qualitative measure of the possible change in relative permeability. As such these simple analytical tools may be used as a screening tool. A positive but imperfect empirical correlation was obtained with results from core flood experiments. The varying concentration of fluorine observed on the rock surface was found to be directly correlated to the wettability change in the rock, which in turn is responsible for improving the deliverability of wells in gas condensate/volatile oil reservoirs. The method discussed in this paper can be successfully used to identify chemical treatments that can change rock wettability and, therefore, relative permeability. This provides a simple and inexpensive way to screen chemicals as wettability altering agents and relative permeability modifiers. In this way the number of HTHP core floods needed is minimized which saves time, cost and effort.

In volatile oil reservoirs, the presence of two fluid phases (gas and oil) near the wellbore is a common problem that affects well deliverability. As the pressure falls below the bubble point the presence of two immiscible phases reduces the oil relative permeability and leads to lower oil production rates. In this paper, we show that the application of fluorinated chemicals can mitigate this impairment associated with gas blocking of volatile oils. We show through laboratory experiments that the treatment not only removes the water from the treated zone, but also modifies the wettability of the rock surface to neutral wet, minimizes capillary trapping and enhances the mobility of oil and gas. The chemical treatment is effective in the presence of connate or flowing water over a range of temperatures. This technique may be used as a curative or preventive treatment in volatile oil reservoirs, potentially increasing oil production rates and recoverable reserves. High-pressure high-temperature (HPHT) coreflood tests were conducted that show that the treatment improved the relative permeability, by a factor of about 1.3 to 2.6 at a GOR of 6000 to 7000 scf/STB in sandstone and limestone cores at low capillary numbers (Nc). Wettability alteration was measured using contact angle and imbibition tests. These tests together with x-ray photoelectron spectroscopy (XPS) analysis were used to screen the selected surfactants. Since this durable enhancement is achieved by treating a small area around the wellbore, it may be applicable in a wide variety of wells.

The use of semisubmersible rigs, subsea trees and workovers in deepwater wells result in costly rig mobilization. Solving problems remotely, with an interventionless method, provides huge savings and fewer risks to the operator. This paper focuses on the preparation of the first global installation of a gravel pack system that allows continuous chemical treatment pumping to the pay zone area without interrupting production. For wells with production issues such as barium and calcium sulfates causing obstruction of the sand-control screen base-pipe holes, this system will allow pumping of scale inhibitors (or any other chemical treatment) to the end of the horizontal well (toe) or to other parts of open-hole or cased-hole sections without needing to stop production. This system was designed to allow continuous pumping of chemicals to inhibit scaling, corrosion and other production-related issues through one small-diameter flowline down to the interior of the sand control screens at two or more distinct parts of the well (while the well is still producing) or per a specific treating program. The number of injection nodes with the same flowline conduit can vary from well to well because the system incorporates zonal isolation with feed through capabilities, using reactive element packer and multiple sequential injection nipples technology. The first installation will require only two nodes. The system allows for screen assembly and gravel pack installation in one trip, while the flowline conduit reconnects the upper string assembly, using an anchor reconnect seal assembly. For the horizontal open hole installation, the system also incorporates a high-flow liner system for flowline conduit/sensors protection and a special feed through quick connector to simplify certain steps in the assembly, and it allows for torque transmission in open hole deployment. This paper will describe the system functionality, identify its main components and present the test program developed to demonstrate the system consistently, qualifying it for field installation.

Many gas wells suffer a loss in productivity due to liquid accumulation in the near wellbore region. Chemical stimulation may be used as a remedy, by altering the wettability to non-liquid wetting. Successful treatments decrease liquid trapping, increase fluids mobility, and improve the well’s deliverability. This paper presents the first effective chemical treatment to mitigate liquid blocking in carbonate gas reservoirs. Screening tests were developed to quickly and effectively identify suitable chemicals from a large pool of compounds. X-ray Photoelectron Spectroscopy (XPS) measurements and drop imbibition tests with water and n-decane were found to be necessary but not sufficient indicators of the effectiveness of the chemicals and were used as screening tests. An integral part of the development of the treatment solution was the selection of a solvent mixture capable of delivering the fluorinated chemical to the rock surface. The treatment solution, mixture of chemical dissolved in solvent, must be stable in the presence of both brine and condensate so that it will not precipitate and will not reduce permeability of the rock. We demonstrate measured relative permeability values in Texas Cream limestone cores (TCL) from high-pressure, high-temperature (HPHT) coreflood experiments before and after treatment. Measurements were made using a pseudo-steady-state method with a synthetic gas-condensate mixture. To enhance the durability of the treatment a special amine primer is introduced. The gas relative permeability increased considerably, about 80%, after the treatment compared to that before treatment. This increase remained substantial, greater than 60% after injection of more then 1000 pore volumes (PV) of gas-condensate mixture. We found an even greater increase in gas relative permeability during unsteady displacement of water by methane. The improvement remained after injecting 20 PVs of brine and increasing the temperature in the treated core from 175 °F to 275 °F. The chemical treatment developed in this research can be applied to increase well deliverability and final recovery of both gas and condensate in the field, providing that it is properly designed by considering key parameters such as reservoir pressure and temperature, brine salinity, and initial water saturation.

SummaryAlteration of wettability from liquid wetting to intermediate gas wetting has great potential in improving gas well productivity from water-blocking and condensate blocking in gas reservoir. Presence of some salt ions such as Na+ even in small quantities in the initial water in the rock has detrimental effect on the alteration of wettability. Berea cores are usually used in laboratory flow studies including in the alteration of wettability. In this work, we present a comprehensive study on the use of Berea, both unfired and fired, in single and two-phase flow with a focus on salt effect on wettability alteration. Three fluoro-chemicals are used in the treatment. We find that one of the three, a nonionic polymeric surfactant is very effective in the alteration of wettability in fired Berea with and without initial salt presence in the rock. The treatment efficiency of ionic surfactants is reduced at the presence of initial salt.

Formation damage minimization and removal are important factors in enhancing field productivity and achieving targeted production rate. While formation damage is anticipated during drilling, an effective wellbore cleanup fluid becomes essential to remove mud damage and enhance well productivity. Filter cake layer created by drilling fluid can impair production considerably and should be removed prior to production using an effective treatment. Filter cake can be removed using a chemically designed filter cake removal treatment. The design of the treatment requires considerations of mud type and reservoir conditions. Also, it is important to consider the compatibility aspect of the treatment fluid with formation fluids and drill-in fluid base oil. Incompatible fluids result in precipitation which leads to further formation damage. In Saudi Arabia, many sandstone reservoirs are drilled with invert emulsion drill-in fluid to avoid the risk of clays swelling, which can lead to hole sloughing and formation damage. However, production impairment due to mud damage effect was observed in some horizontal wells drilled with invert emulsion drill-in fluid and completed with stand-alone screens as a result of improper mud managemet. After being put on production, their production rates have been reduced significantly with time. The decrease in production was related to screen blockage and mud cake impairment. A newly developed single-stage treatment was spotted and soaked to remove oil based mud cake and screen blockage. A significant sustained improvement in production was noticed and flowback solids indicated removal of screen blockage and mud cake. Lab studies were conducted at reservoir simulated conditions to evaluate the effectiveness of the treatment. The study covered testing the treatment filter cake removal efficiency, return permeability tests with reservoir core samples, and compatibility tests with formation fluids and drill-in fluid base oil. This paper will discuss in detail the laboratory work conducted and the successful field treatment performed.

Different laboratory models were elaborated and applied to fields for HC enhanced recovery. Most of these models performed a 1.6 to 4.7-fold increased reservoir filtration proprieties. In some rare cases, the applied treatment has not improved the recovery, while only in two cases the procedure resulted in production degradation. Undesirable effect was due to the partial dissolution of some rock fabric constituents such as opal and chalcedony by HCl and HF. Acid treatment involves also surface activation, which results in increased amount of the mineral-bound water and, consequently, in decreasing rock permeability. This requires stabilization of swellable clay minerals. For this purpose, the treatment of reservoir rocks from northern Saharan fields with calcium chloride performed increase of reservoir filtration capacity for two- or even three-fold. The repeated treatment has not produced a substantial increase of the permeability. The favourable effect of CaCl2 treatment is plausibly explained by the change of the film thickness of bound water in the pore space as well as by the replacement of Na+ cations by Ca2+ cations in swellable clay minerals. This process promotes also the dehydration of sandstone clay cement and desorption of asphaltenes and resins in the stratum. The treatment of the argillaceous cement of sandstone in the reservoir with KCl, HCl and CaCl2 solutions produced decrease in clay swelling by 10 to 50 %. However, the inclusion of solvents, inhibitor agents such as monovalent and polyvalent salts, polymers, emulsion agents and some crude fractions considerably improves protection and stabilization clay minerals in sandstone cement and contribute to minimizing the reservoir plugging. The described approach is at present extended and applied successfully to fields in other basins.

A series of three fixed platforms off the California coast produce fluids sourced from sandstone and carbonate formations that individually produce brines with substantial amounts of calcium and bicarbonate, respectively. These fluids are sent to a central facility onshore for processing, requiring that the combined fluids be treated for calcium carbonate scale. During acid stimulation treatments of wells, the fluid flowback from the wells initially has very high calcium levels that greatly increase risk of scale formation for a short period of time. To better understand the dynamic scale risk created during stimulation flowback, a monitoring program using a novel in-line deposition monitoring probe was implemented. The probe was placed in-line at the onshore processing facility to track changes in the production fluids prior to and during the acid stimulation program. The resulting data was correlated to several events that occurred within the process including a process shut-in, deposition of heavy oil residue that fouled the probe during a period of poor separation, and scale deposition upon reduced chemical treatment.Real-time data obtained during flowback from two acid stimulation jobs is presented, demonstrating how it was possible to optimize the scale inhibitor treatment program such that no scale deposition occurred during these treatments. The value of the real-time monitoring data versus other methods of assessing the risk of scale formation within these fluids is highlighted and the ability to optimize inhibitor treatment rates in real-time demonstrated.The development and implementation of on-line real-time monitoring for deposition control of an active and changing scaling environment shows the clear value that this technology brings to scale control within process facilities.

This report documents laboratory studies that display the potential of the new iron sulfide treatment that, instead of preventing the formation of the scale, allows a dispersed iron sulfide to form that is both water wet and deactivated. Evidence has been provided that shows how the treatment keeps the particle size small so that is unlikely to associate and deposit in production systems. The mechanism of control is and the parameters that control the performance are discussed. The dispersant facilitates the transport of the scale with the produced water but prevents the FeS from forming pads at water-oil interfaces. Results from a limited field trial demonstrate the success of the treatment in the preventing the formation of pads in a primary separator, and solids deposition in a heater treater.

Abstract Most gas condensate wells, including hydraulically fractured wells, are operated at pressures below the dew point pressure of the reservoir causing condensate to drop out and accumulate near the wellbore, thus blocking the gas production. Even for very lean gas condensate fluids, once the bottom hole flowing pressure falls below the dew point pressure, the condensate bank forms in a matter of months and leads to a rapid decline in production from these wells. In hydraulically fractured gas condensate wells, condensate can build up to very high saturations in and around the fracture which significantly reduces the productivity of these wells. Two-phase gas condensate flow measurements have been conducted under reservoir conditions in a propped fracture to study the damage caused by condensate blocking in fractures. An in situ chemical treatment has been developed to reduce the damage caused by liquid blocking of hydraulically fractured wells by altering the wettability of the proppants to neutral wet, thus reducing the residual liquid saturations and increasing gas relative permeability. A fluorinated surfactant in a glycol-alcohol solvent mixture was found to improve the gas and condensate relative permeabilities measured on propped fractures by a factor of about 2 under reservoir conditions. Introduction In gas condensate reservoirs, when the bottomhole pressure in flowing wells falls below the dew point pressure of the fluid, a liquid hydrocarbon phase commonly referred to as condensate is formed and is subsequently trapped by capillary forces. The liquid condensate, along with the connate water that is present, continues to accumulate in the rock pores thus impeding gas flow, until a critical liquid saturation is reached that is similar to the residual oil saturation that would form in the same rock under the same flow conditions. Once the critical liquid saturation is exceeded, both the condensate and gas flow towards the wellbore. The liquid continues to accumulate until a steady-state saturation is reached that is somewhat higher than the critical liquid saturation. Condensate banking can reduce the well productivity significantly, in several instances by a factor of 2 to 4. Afidick et al. (1994), Barnum et al. (1995), Engineer (1985) and Ayyalasomayajula et al. (2003) have reported field data that show significant productivity loss due to condensate accumulation. Since the reduction in well productivity is primarily associated with the reduction in gas relative permeability, a great deal of effort has gone into measuring and modeling the relative permeability of gas-condensate fluids. Initially, the studies were done at low pressure and temperature (Ham and Eilerts, 1967). Later studies were done at reservoir conditions with synthetic fluids (Kumar et al., 2006; Ayyalasomayajula et al., 2003; Henderson, 1998) as well as with reservoir fluids (Nagarajan et al., 1998). Various parameters such as interfacial tension (Haniff and Ali, 1990), high flow rates (Henderson et al., 2000; Kumar, 2006), non-Darcy effects (Henderson et al., 2000; Bang, 2007), fluid composition (Bang et al., 2006) and rock type (Bang et al., 2006) have been investigated. Several strategies have been tried and tested for stimulating gas-condensate wells with limited success (Anderson, 2005). Gas cycling (Aziz, 1983; Harouaka and Al-Hashim, 2002) allows the pressure to be maintained above the dew point but may not be economical, especially late in the life of the reservoir when large quantities of injected gas are required to maintain the pressure above dew point.

This paper describes the results of an investigative case study to identify the causes of productivity decline in an oil well and a successful chemical treatment to restore productivity. A well in a Japanese oil field has suffered from a significant productivity decline from the beginning of commercial production. Pressure build up tests have shown the presence of formation damage becoming larger as production goes. Then we considered the possibility of asphaltene deposition, which has been observed in most of the surface facilities, in the near wellbore formation restricting flow capacity around the well. A multidisciplinary team was organized, with field operation engineers and researchers from the R&D center, to investigate the asphaltene behavior in the formation and to find the effective way of chemical treatment as asphaltene-control measures. Laboratory analyses using bottom-hole fluid samples have built the onset pressure curve of asphaltene precipitation, which indicated the asphaltene deposition in the near wellbore region under the production conditions.1 Then the intensive laboratory tests have been carried out to evaluate some commercial additives in terms of their efficiency as an asphaltene inhibitor under the formation conditions and to find the most effective chemical to resolve precipitated asphaltene. Based on laboratory analyses and tests, a complete chemical treatment program consisting of injection of Xylene into the formation with a three feet treatment radius and squeezing of an asphaltene inhibitor around the well has been designed and applied to the well. This chemical treatment resulted in a significant improvement in the productivity index which is almost ten times larger comparing as before.

Organic field deposits from distinct geographical regions were analysed using a wide range of analytical techniques, viz. for cation composition (EDAX), diffraction patterns (XRD), thermal profiling (DSC/TGA), naphthenic acid distribution using electrospray mass spectrometry (ESMS), nuclear magnetic resonance 1H NMR and solid state 13C NMR. Clear distinctions for end member soap types were observed with regard to the type and amount of cations, the naphthenic acid content, as well as their thermal behaviour. Specific soap samples were analysed along with their parent soap forming crude oils collected from the same field over a period of one year. The nature of two of these soap samples were found to be related to the particular chemical treatment on site. There were clearly observable differences in the final location within the surface facility, as well as the final composition (calcium content, acid distribution, presence of other chemical families) of these samples. These were suggested to be related also to crude oil chemistry changes and mitigation (chemical) strategies used. The implications of these new findings on the basic mechanisms of soap formation are discussed.

Incursion of subterranean tar into the wellbore during and/or after drilling has the potential to result in a variety of problems. If the tar is soft and deformable, it may ‘refill’ the wellbore and require additional drilling time and casing operations. An additional problem is adhesion or accretion of the tar directly onto the drillstring or bottom-hole-assembly (BHA). Such fouling of the drillstring/BHA often requires unplanned tripping to physically remove the adhered tar. It is also conceivable that the tar-related problems may ultimately result in the hole being plugged and abandoned. For these reasons, an approach has been developed to (1) emulate the reported wellbore accretion, and (2) develop lab-based approaches to help minimize/reverse the tar adhesion. Investigation of tar accretion onto steel rods/tubes with a Gulf of Mexico tar was studied in a synthetic-based mud, to evaluate possible avenues of remediation. In addition to evaluating the conditions necessary to induce tar accretion in the laboratory, further studies were performed to affect reversal of the intentional accretion and also to help prevent initial accretion. Included are the results from the induced accretion and various additive-based attempts to mitigate the tar adhesion. In order to induce lab-based accretion, it proved necessary to develop a testing method to emulate the scope of tar accretion observed in the field. This methodology is herein described along with the optimized fluid system. Of specific interest in this study is the ability to use this novel fluid either as a sweep, spot or additive as a means to help reduce the inherent ‘tackiness’ of the tar and thereby help reduce/prevent the adhesion to the emulated drill string. The fluid treatment developed is environmentally acceptable and uses a novel chemical composition which proved successful in reversing and preventing tar accretion under the laboratory experimental parameters.

A vertical well has a history of problems which has contributed to its disappointing performance. A 15 wt% HCl acid treatment was performed in an attempt to remove drilling mud filter cake and improve wellbore to formation connectivity, however the solubility of the formation's cementation material (calcite) was overlooked and sand production resulted after the treatment. A screen liner running operation was then performed, with a need for sand control, and massive mud losses and polymer pills were lost to the formation during the process. The workover fluids were displaced deep into the formation while loading the hole to maintain well control. The presence of biopolymers in the completion fluids enhanced the activities of sulfate reducing bacteria (SRB). These bacteria further compounded the problem, and the damaged environment was ideal to initiate the production of plugging FeS and biomass in the near wellbore region. Ultimately, the formation was not able to deliver the necessary flow rate to supply the ESP pump when the well was returned to production. The damage mechanism is a combination of polymer residue, biomass and FeS plugging the screen liner. A three-stage treatment was designed to remove the damaging material. The first stage was based on tetrakishydroxy methyl phosphonium sulfate (THPS) and was designed to remove iron sulfide and hydrogen sulfide, and control the growth of bacteria. The second stage was based on formic acid and was intended to remove FeS and some of the polymer residue in the near wellbore area. The third stage was based on a two-part oxidative treatment and was designed to remove polymer damage deep in the formation. Analysis of well flowback samples before and after the treatments was used to confirm the damaging mechanisms and to evaluate the treatment. This paper reviews the procedure used to identify the problem, and the unique treatment which successfully restored well productivity.

Water producing gas wells may suffer from liquid loading and get killed or their water production may exceed the capacity of the water handling facilities. Just closing off the water producing zone may be unacceptable if they have a large contribution to the gas production. A near well bore chemical treatment using a polymer solution is an option to reduce the water production and maintain the gas production. Once adsorbed to reservoir rock, the polymer may significantly reduce the relative permeability to water in the near well bore area. Hundreds of gas wells of the Nederlandse Aardolie Maatschappij (The Netherlands) suffer from water production. A simulation study using a radial single well model was carried out to look after the feasibility of a treatment. The study shows that a treatment based on reduction of the water relative permeability causes a choke effect: both the water and gas flow rates are reduced instead of only the water rate. Moreover, the benefits of a treatment are tempered because of a clean-up effect after injection of the chemicals. A reduction in the water/gas ratio by a factor 2 requires a reduction in the water relative permeability by at least a factor 10. A well which was killed due to liquid loading at a high water/gas ratio and with a high contribution to the gas production by the water producing interval is a suitable candidate for treatment. A treatment may also be considered for a well of which the water production exceeds the capacity of the water handling facilities. Provided that the flowing tubing head pressure can be significantly lowered, the loss of gas production from the water producing zone can be compensated by increased gas production from the other intervals.

With the emphasis being placed on environmental safety in recent years, companies are seeking economical methods for cleaning oil field waste. Drilling operations produce substantial amounts of such waste in the form of cuttings and used drilling mud. Oil-based or synthetic based muds, which are necessary in some drilling situations, increase the difficulty of cleanup operations due the increased hazards these fluids pose to the environment. One chemical washing agent has been identified that demonstrates potential for successfully reducing the TPH content of oil-based mud cuttings to below the required level.

Sulfate-reducing bacteria (SRB) are notorious for causing decreases in the quality of oilfield injection waters due to their ability to increase total suspended solids (TSS). Through dissimilatory respiration, SRB reduce sulfate to sulfide, which subsequently forms hazardous hydrogen sulfide (H2S) gas. H2S is not only an environmental health threat, but it also can indirectly contribute to decreased water injectivity by reacting with soluble iron to form iron sulfides. These very tenacious solids can plug formation faces, thereby reducing the volume of water a well can take at a specified injection pressure. A previously reported study showed that an anthraquinone treatment program was capable of controlling biogenic H2S generation while maintaining TSS within field specifications (SPE 50741). Subsequently, an anthraquinone program was initiated in Chevron's Lost Hills Field (California) produced water injection system. Chevron's water treatment program had been a continuous injection of a quaternary biocide compound plus a weekly slug dose injection of another biocide (acrolein) to control SRB, TSS and H2S. Chevron also maintained a monthly pigging program that required the disposal of classified hazardous wastes due to the continuous injection of the quaternary chemical. The new treatment program included weekly slug injections of acrolein followed by a slug dose of a soluble form of anthraquinone. The monthly pigging program was maintained, but the continuous quaternary compound usage was eliminated. This paper describes the produced water injection system, the treatment program and the parameters monitored, including TSS, SRB, and H2S levels before and after the implementation of the anthraquinone treatment program. These data show that the new program has resulted in injection water quality which is currently better than previously measured during the recent history of the field and which now for the first time consistently meets Chevron's TSS specification.

Sludge removal from a storage tank is an easy task if the objective is just to increase the storage capacity. However, sludge transformer in crude oil is much desirable in order to benefit from the value of the recovered crude. Desludging approaches used could be chemical or mechanical. The objective of this paper is to evaluate both these approaches and propose the most cost effective methodology in tank cleaning operations. No doubt that performing the cleaning task without opening the tank is of advantage. Also working without adding chemical products, heating or applying steam is safer for the facilities and the workers. Other aspects that are discussed in the paper include the need to eliminate pollution of air and soil, in addition to changing the sludge into crude which can be sold in the international market. Furthermore, real examples are discussed in the paper where the sludge in the tank was about 30.7 ft and the cleaning process is explained in detail. One of the examples shows how 74 676 barrels of sludge changed to crude in only 37 days by optimizing the applied technique.

Abstract Laboratory studies have been carried out to assess the comparative effectiveness of chemical treatment and thermal conditioning on the crude oil being produced from Eocene formations by Oil India Limited (OIL) in the upper Assam region of India. The studies have indicated that the present Eocene crude is amenable to both thermal conditioning and chemical treatment, and combination thereof. The study has shown that he thermal conditioning of crude has distinct advantage over chemical treatment in terms of improvement in rheological parameters, reduction in pour point and remarkable reduction in depositional characteristics. However, the thermally conditioned Eocene crude has shown some ageing effect, and has poor thermal stability. P. 271

Abstract This paper presents a novel scale inhibitor chemistry for achieving cost effective and extended squeeze lifetime in high water producers that can significantly reduce the number of treatments. The new and proprietary concept called Mobil Scale Inhibitor Process (MSI) is based on additives in the scale inhibitor solution that activate the phase separation of up to 85% of the total injected inhibitor during the well shut-in period following afterflush. Such an inhibitor retention is much higher than obtainable by conventional adsorption or precipitation mechanisms. The activation is temperature, time and pH driven and allows the inhibitor slug to be safely displaced into the formation before phase separation occurs. Furthermore, this squeeze chemistry can be applied to most of the commonly used scale inhibitors such as phosphino-polyacrylic acids (PPAA), polyacrylic acids and phosphonates to improve their squeeze performance. MSI is environmentally friendly and has an OCNS (Offshore Chemical Notification Scheme) category of zero. In corefloods with either PPAA or phosphonates under simulated North Sea reservoir conditions, this new chemistry resulted in a 2–12 fold increase in the squeeze lifetimes. Computer modeling predicts significant increase in inhibitor lifetime when applied in the field. To date, field trials by Mobil North Sea Limited support the laboratory work and well productivity was not damaged. This new technology is believed to be a significant advance in achieving long-lasting and cost-saving downhole squeeze treatments for preventing scale deposition, particularly for high water producing wells. Furthermore, it does not increase complexity in field operation when compared with conventional treatments. Introduction The Beryl Field is located 200 miles northeast of Aberdeen, Scotland in U.K. Block 9/13. It is estimated to have contained some 2.6x109 STB of oil and 3.2 x109 scf of gas initially in place. It consists of six main reservoir horizons ranging in age from Upper Triassic to Upper Jurassic with the Middle Jurassic Beryl Formation containing about 80% of the total reserves. The Beryl Alpha platform began production by primary depletion in June 1976. Pressure maintenance was initiated by gas injection n 1977 and augmented by seawater injection in 1979. The Beryl Bravo platform came on stream in July 1984. Gas and seawater injection to maintain reservoir pressure was started in 1984 and 1987, respectively. Currently, the Beryl Field has 27 of 50 producing wells producing over 100 BWPD, several producing over 5000 BWPD. Seawater breakthrough has been seen in 18 of the 27 wells. Since gas export began in October 1992, Beryl reservoir pressures have dropped significantly to 1000 to 5000 psi. Average pressures on the Alpha wells are 2500 psi compared to 4000 psi on the Bravo wells because of greater reservoir depletion rates. Typical field production rates are 110,000 BOPD and 60,000 BWPD. Injection rates average 260,000 BWPD. Gas export rate is 4x 108 scf/D. Reservoir temperatures vary from 200 to 225 F. Both carbonate and sulfate scales were encountered since the early 1980's. Since 1987 Mobil has aggressively squeezed scale inhibitors. Following a successful three-well test in 1989, the Mobil Long Life Scale Inhibitor (MLLSI) has been routinely used at Beryl. MLLSI is based on the cross linking of PPAA to enhance its adsorption on sandstone rocks. An average treatment life of 12 to 16 months has been obtained with MLLSI compared to 6 to 8 months with other commercial treatments. For a major part of the MLLSI treatment, returns were 1 to 2 ppm which limits the protection against more severe scaling conditions. P. 453

Abstract With potential increase in water injection requirement, increase in oil production rate and the unavoidable increase in water production, an improvement in the chemical treatment programmes was deemed to be necessary in the mid eighties. As a result, an assessment of the chemical treatment programmes philosophy was carried out in the Statfjord field. The assessment programme philosophy covered different aspects of all chemicals used for the water injection systems, process systems as well as utility process related facilities, such as, ballast water systems, heating and cooling systems and fire water systems on the three Statfjord platforms. The assessment programme was intended to improve the methods used for selecting chemicals for the different systems and improve the application and the daily follow up of the chemicals offshore. Consequently, a better control on the consumption of the chemicals in the field can be achieved, as well as reduce the environmental impact and risk of the use and discharge of production chemicals in the North Sea. The objectives were achieved by adapting a systematic approach in the selection and application of chemicals. The issues covered in these objectives included: Clearer definition of individual problems in the systems Select suitable simplified methods for testing new chemicals, either onshore or offshore System parameters optimisation included in the testing programme for chemicals Chemicals characteristics end partitioning in the individual systems The toxicity of chemicals and biodegradability The handling aspects of chemicals by offshore personnel Improvements and upgrading of the chemical injection facilities Establish operation procedures in order to implement and follow up the required treatments Improve the chemical injection facilities on the platforms In addition, a training programme was introduced for operation personnel, in order to improve the level of knowledge as well as understanding of chemical treatment requirements, and the importance of these programmes in maintaining stable operation and in reducing fluid handling related problems. Having completed the assessment and the implementation of the new chemical treatment programme philosophy by the late eighties, a new chemical treatment and management system was established on Statfjord platforms. The outcome of such an approach was, more effective treatment, as well as reduced cost and quantity of chemicals used per volume of oil produced, treated produced water and treated injected water. With the increased environmental awareness, the new procedures gave a better and an instantaneous view on the level of used and discharged chemicals. Such data are required for regular reporting to the environmental authorities. The experience gained over the past few years has been also used in improving the design of the required chemical injection facilities on newly developed platforms, as well as chemical treatment programmes on newly developed fields. Introduction Statfjord field is located in the straddle between the Norwegian sector and the British sector of the North Sea, approximately 100 miles west of the Norwegian coastline. The Statfjord field is considered one of the biggest in the North Sea in terms of current production and recoverable oil. The field consists of three Condeep platforms. The production on Statfjord platforms is based on oil recovery from two reservoirs, Brent and Statfjord, currently utilizing 66 wells for oil production. Current total production from the three platforms is approximately 125000 Sm3/day of oil and 28 MMSm3/day of associated gases. The field currently handles 35000–40000 Sm3/day of produced water. The field has three water injection systems, with total current injection capacity of 200000 Sm3/day of sea water, used to maintain pressure in the Brent reservoir. Some of the produced gas is re-injected into the Statfjord reservoir as part of the oil recovery and pressure maintenance in this part of the field. In addition to the production from the Statfjord field itself, the Snorre field in the vicinity of the Statfjord field is currently utilizing the field process facilities in stabilizing produced fluid as well as handling the gas, after partial process stabilization on the Snorre platform. Future development in the area will also utilize the field facilities in totally handling produced fluid and gas from adjacent satellite fields, namely, Statfjord North and East development. Fig. 1 shows the lay-out of the Statfjord field and the new developments which are already linked or will be linked to Stafjord facilities. The water injection systems on Statfjord platforms consist of backwash 80 micron filters and gas stripping deaerator. Fig. 2 illustrates the water injection system utilized in the field. The oil and produced water handling facilities on Statfjord platforms are illustrated in Fig. 3. The process trains on Statfjord platforms consist mainly of four stage separation and stabilization vessels, in addition to a fifth vessel for improved water separation. The five stage separators are; the inlet separator with three phase separation; flash drum 1 with three phase separation; flash drum 2 and 3 for gas separation and oil stabilization; and the coalescer for improved water separation. Aspects and problems related to chemical treatment requirements on Statfjord platforms have differed with the changes over the years in the composition of the produced fluid.

SPE Member Abstract Paraffin and scale deposition in wells at Conoco's Paraffin and scale deposition in wells at Conoco's Chittim lease has consistently hampered operations. Numerous chemicals were laboratory and field tested to determine the two most cost-effective chemicals for paraffin and scale treatment. These were a paraffin solvent and a sulfamic acid system, paraffin solvent and a sulfamic acid system, respectively. Gross lease revenue has increased substantially with the use of the two chemicals in a fieldwide treatment program. Introduction Conoco Inc. operates a shallow waterflood on the N. J. Chittim lease, Sacatosa Field, Maverick County, Texas, which consists of 628 producing wells and 580 injection wells. Current field production is approximately 3700 BOPD. Unfortunately, scale and paraffin deposition in these wells has consistently caused operating problems:plugged perforations, pumps, and problems:plugged perforations, pumps, and flowlines,frequent well pulling, andreduced mechanical oil/water separation. A study was undertaken in 1983 to determine the most cost-effective chemicals and treatment procedures that could be applied on a fieldwide basis to minimize operating problems due to paraffin and scale. Extensive laboratory and field paraffin and scale. Extensive laboratory and field testing of seven chemicals indicated a paraffin solvent and a sulfamic acid to be most cost-effective. Consequently, a continuous chemical treatment program was implemented utilizing these two chemicals. SELECTION OF TEST CHEMICALS Paraffin Chemicals Paraffin Chemicals Five major chemical companies were provided with a sample of Chittim paraffin collected from pulled tubing. Each chemical company's sales representative was asked to determine the most effective solvent they could offer to treat the paraffin. Each vendor then supplied a sample of the recommended solvent. A Paraffin Flask Test was used to compare the efectiveness of the five different solvents as folows: Lease water (100 mls) was placed into each of six clean bottles. A four gram ball of Chittim paraffin was then placed in each bottle. Next, 0.5 ml of the recommended paraffin solvent was placed in five of the paraffin solvent was placed in five of the bottles. Chemical was not added to the sixth bottle which served as a blank. All bottles were then placed into a hot water bath, approximately 190 degrees F, until all of the paraffin melted. The samples were then paraffin melted. The samples were then removed from the hot water bath and agitated simultaneously until the paraffin resolidified (approximately 10 minutes). Effectiveness of the five chemicals was visually judged according to the following checklist:Size and shape of resolidified paraffin particles - an effective paraffin solvent yields small (1-2 mm diameter) balls floating on the surface of the water that resemble coffee grounds. The tiny, non-adhering balls indicate that the solvent has good dispersing characteristics and will prevent the paraffin from reagglomerating.Paraffin adhering to bottle - paraffin adhering to the test bottle or cap indicates that the chemical is not totally effective in preventing paraffin redeposition. Consequently, the more paraffin remaining on the sides of the bottle, the less effective the chemical is in limiting redeposition. A good solvent will not allow any paraffin to cling to the bottle.

Abstract A new chemical treatment has been developed to stimulate problem sandstone formations. This treatment is designed to overcome a commonly observed problem in which wells initially respond to matrix acidizing but show rapid production declines following treatment. These rapid declines are generally attributed to migration of clays and other fines. The treating fluid, which slowly generates hydrofluoric acid, reacts more slowly than conventional Mud Acid and thus penetrates a greater distance into the formation before spending. The fluid also acts to stabilize clays and other fines by chemically fusing them to the sand grains. The chemistry of this system is entirely different from that previously reported in the literature. The effectiveness of this stimulation and clay control method is demonstrated by core test studies. The control mechanism is illustrated by scanning electron microscope studies and x-ray analyses of treated clays. Field test results are also presented. presented Introduction Sandstone matrix acidizing has long been used as a means of improving production of oil and gas by removing formation damage and increasing permeability of the zone immediately around the permeability of the zone immediately around the wellbore. Laboratory and field studies have demonstrated the effectiveness of this type treatment. In spite of widespread use, however, many formations do not respond satisfactorily to conventional HCl/HF acid (Mud Acid) treatments. This is normally attributed to rapid spending of HF near the wellbore. Some wells initially show good stimulation but later experience an unusually rapid decline in production rate. Such production declines are commonly observed in wells producing from unconsolidated sands and are usually attributed to plugging by migratory clays and other fines. Plugging by Migratory Fines Plugging by Migratory Fines Formation plugging by migratory fines was demonstrated by Krueger et al in both laboratory and field studies. Core test results revealed that high flow rates caused dislodgment of fines with resulting loss of permeability. Krueger also reported field studies in which the production decline rate was accelerated by flowing wells above an optimum rate. As the production rate was increased, a corresponding increase in inorganic solids content of the produced oil was also observed. These observations strongly support the theory of formation damage from fines migration. Migratory fines are apparently released first by exposure to strong acid and later by mechanical forces resulting from the increased flow of produced fluids. Various treatments and produced fluids. Various treatments and production techniques have been devised in an effort production techniques have been devised in an effort to control or minimize this problem. Krueger and Templeton described treating techniques in which wells, following stimulation, were returned to production at a gradually increasing rate in order production at a gradually increasing rate in order to minimize fines migration. Various clay stabilization agents have also been applied in an effort to control movement of fines. Delayed acting acidizing systems have been developed to provide deeper live acid penetration and thus provide deeper live acid penetration and thus remove damaging fines some distance from the wellbore. A new retarded HF acid system (Clay Acid) has proven extremely effective for matrix acidizing proven extremely effective for matrix acidizing sandstone formations. The Clay Acid is usually applied as an overflush to Mud Acid. Upon entering the formation, the Clay Acid slowly generates hydrofluoric acid thus providing greatly increased live acid penetration. The system requires neither the use of flammable organic esters nor multiple staging of treating fluids for HF generation. In addition to providing deep live acid penetration, the treatment also stabilizes any undissolved clays contacted. In contrast to conventional clay stabilizers, which act by ion exchange or adsorption, Clay Acid produces an actual chemical fusion of fines and clay platelets.

Abstract A new method of treating gas storage systems for internal corrosion protection has been developed. Previous methods involved expensive individual Previous methods involved expensive individual well treatment by truck. Also, side effects such as foaming and emulsions sometimes caused problems. A continuous treatment method for gas-lift systems is briefly discussed. A single point, centrally located system of injection for chemical treatment has been developed and field proven. The program included means of detecting corrosion initially and monitoring corrosion control as provided by a three phase corrosion inhibitor designed for gas storage systems. Introduction The gas industry has long known the value of its investment in gas storage reservoirs, compressor stations, pipelines and related equipment. However, only in the last few years has more detailed attention been given to internal corrosion protection for well tubing and casing and injection and withdrawal Pipelines. This increased focus on internal corrosion has been brought about by the increased need to maintain gas supplies during critical periods caused by recent gas shortages. Further inflation has drastically increased replacement costs of pipe and equipment not to mention labor costs. Therefore, there has become an increased need for an economical, efficient, dependable method of applying corrosion protection to the internal surfaces of gas storage facilities. Early treatment of gas storage systems was by truck at each individual well. Wright and Kepley reported ten years ago on a method of using a corrosion inhibitor-biocide by truck. This method is much more expensive by modern day standards and foaming of the chemical mixture was at times a problem to the storage field operations although problem to the storage field operations although the method and treatment was effective. In 1975, Mutti, Atwood, Lafayette, and Landrum reported on a method to treat a gas lift system from one or more points. This method was the use of a venturi to atomize and disperse a corrosion inhibitor into the gas lines going to the various individual wells to prevent corrosion in the tubing and wellhead equipment. It was found that this method did not disperse the chemical into the gas stream well enough to be distributed properly to each well. The method was modified properly to each well. The method was modified to use more injection points with divider valves. A further modification of this method was to use electronic timers to alternately allow inhibitor to be pumped to individual wells for a specific length of time. Although these methods proved effective in controlling downhole tubular corrosion, they are expensive to install and maintain. It was thought that an improvement could be made in both the method of application and the type of corrosion inhibitor to use. A three phase corrosion inhibitor has been developed for gas storage systems and related gas handling facilities as reported by Stanford, Chappell, Robertson and Hawsey. This material was designed to carry with and film from gas, water, and hydrocarbons. It is a light weight effective material that will carry long distances with the gas steam. However, an economical, effective and defendable method was required in order to apply the material so that distribution to each individual well could be assured. The system developed called a Retractable Atomizing Chemical Injector, is simple and effective. It consists of a packing gland that contains a one quarter inch pipe or "stinger" to which is attached an atomizing nozzle. The packing gland attached to a one inch nipple is packing gland attached to a one inch nipple is then installed on a full opening valve. The valve may be a one inch, but a larger valve bushed down to a one inch is preferred. After the packing gland is tight, the valve is opened and the packing gland is tight, the valve is opened and the atomizing nozzle is forced into the gas stream by adjusting two draw bars installed above and below the packing gland by two all thread rods. The nozzle is moved to just inside the pipe wall.

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. This paper was prepared for the Improved Oil Recovery Symposium of the Society of Petroleum Engineers of AIME, to be held in Tulsa, Okla., March 22–24, 1976. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and with the paper, may be considered for publication in one of the two SPE magazines. Abstract Many different approaches have been used in an effort to minimize water injectivity impairment within an acceptable cost range. Certainly the selection of criteria to use as a yardstick when evaluating performance will have a significant impact on performance will have a significant impact on the useful nature and validity of the results. Burmah Oil and Gas Company has been reinjecting produced waste water into the Lower Main Zone reservoir at Huntington Beach, California, during the past three years. A discussion of the problems which have had a direct affect on injectivity impairment is presented, along with the chemical and presented, along with the chemical and mechanical approaches which have been implemented to solve these problems. In conclusion, well and water quality data are analyzed which, hopefully, give a fair representation of the performance. performance. Pilot waterflooding and the first full scale flood expansion were initiated using sea water from a shallow aquifer. Also, injection into the wells was down both tubing and casing-tubing annulus, neither of which were internally coated. Subsequent environmental considerations and the Ocean Discharge Plan of 1972 resulted in the decision to Plan of 1972 resulted in the decision to reinject produced water into the Lower Main Zone. Discussion Prior to the initiation of waste water re-injection into the Lower Main Zone, an extensive review was conducted to establish parameters which would have an affect on parameters which would have an affect on injectivity impairment. Limits were established for suspended solids, oil, and dissolved hydrogen sulfide. It was felt that if the limits were exceeded, injectivity impairment would result. Using these parameters, facilities were designed to effect the parameters, facilities were designed to effect the desired removal efficiencies. The designed and subsequently installed treatment facilities are described below: Water from free water knockouts is processed through skim tanks, retention tanks, processed through skim tanks, retention tanks, flotation cells, and a filter plant prior to reinjection. A diagram of the facilities is presented in Figure 1. The only significant variation compared to other similar operations in the Los Angeles Basin is the removal of dissolved hydrogen sulfide prior to reinjection. Biologically induced corrosion problems observed during the pilot flood were more difficult to control as a result of ferrous sulfide accumulations throughout the injection system, although the sea water was dissolved-hydrogen-sulfide-free.

Abstract A new chemical treatment has been developed to stimulate problem sandstone formations. This treatment is designed to overcome a commonly observed problem in which wells initially respond to matrix acidizing but show rapid production declines following treatment. These rapid declines are generally attributed to migration of clays and other fines. The treating fluid, which slowly generates hydrofluoric acid, reacts more slowly than conventional Mud Acid and thus penetrates a greater distance into the formation before spending. The fluid also acts to stabilize clays and other fines by chemically fusing them to the sand grains. The chemistry of this system is entirely different from that previously reported in the literature. The effectiveness of this stimulation and clay control method is demonstrated by core test studies. The control mechanism is illustrated by scanning electron microscope studies and x-ray analyses of treated clays. Preliminary field test results are also presented. Introduction Sandstone matrix acidizing has long been used as a means of improving production of oil and gas by removing formation damage and increasing permeability of the zone immediately around the wellbore. Laboratory and field studies have demonstrated the effectiveness of this type treatment. In spite of widespread use, however, many formations do not respond satisfactorily to conventional HCl/HF acid (Mud Acid) treatments. This is normally attributed to rapid spending of HF near the wellbore. Some wells initially show good stimulation but later experience an unusually rapid decline in production rate. Such production declines are commonly observed in wells producing from unconsolidated sands and are usually attributed to plugging by migratory clays and other fines. Plugging by Migratory Fines Formation plugging by migratory fines was demonstrated by Kruger et al in both laboratory and field studies. Core test results revealed that high flow rates caused dislodgment of fines with resulting loss of permeability. Kruger also reported field studies in which the production decline rate was accelerated by flowing wells above an optimum rate. As the production rate was increased, a corresponding increase in inorganic solids content of the produced oil was also observed. These observations strongly support the theory of formation damage from fines migration. Migratory fines are apparently released first by exposure to strong acid and later by mechanical forces resulting from the increased flow of produced fluids. Various treatments and production techniques have been devised in an effort to control or minimize this problem. Kruger and Templeton described treating techniques in which wells, following stimulation, were returned to production at a gradually increasing rate in order to minimize fines migration. Various clay stabilization agents have also been applied in an effort to control movement of fines. Delayed acting acidizing systems have been developed to provide deeper live acid penetration and thus remove damaging fines some distance from the wellbore. A new retarded HF acid system (Clay Acid) has proven extremely effective for matrix acidizing sandstone formations. The Clay Acid is usually applied as an overflush to Mud Acid. Upon entering the formation, the Clay Acid slowly generates hydrofluoric acid thus providing greatly increased live acid penetration. The system requires neither the use of flammable organic esters nor multiple staging of treating fluids for HF generation. In addition to providing deep live acid penetration, the treatment also stabilizes any undissolved clays contacted. In contrast to conventional clay stabilizers, which act by ion exchange or adsorption, Clay Acid produces an actual chemical fusion of fines and clay platelets.

Abstract The use of a crystal modifier to control paraffin deposition in hydraulically pumped wells in Hartzog Draw has pumped wells in Hartzog Draw has proven successful. There are currently proven successful. There are currently thirty wells, 11,000 BOPD, being treated chemically for paraffin. Before the chemical program was initiated, the wells were being treated by hot oiling. The frequency of hot oiling the wells averaged as high as three times per month. This cost, along with paraffin cleanouts with workover equipment and frequent pump repairs, caused high operating costs. Therefore, a chemical treatment program was implemented. Data were gathered for each well before and after chemical treating. The total cost for hot oiling versus chemically treating the wells showed a savings of 20% per month. The cost of chemical has been per month. The cost of chemical has been reduced which in turn has lowered the treating costs from $.16/bbl. initially to $.10/bbl. currently. Some of the wells have shown production increases one to two months after chemical treating was initiated. This is due to keeping the entire system cleaner and reducing the plugging of the formation with paraffin, a result of hot oiling. This paper will document the data collected and further impress the fact that chemical treatment of paraffin is far superior to hot oiling. Introduction The Hartzog Draw Unit is a three hundred (300) well field in the Powder River Basin in northeast Wyoming (Figure 1). The producing horizon is the Shannon Sandstone. The oil gravity of Shannon crude is 35 degrees API. Current production from the field is 18,500 bopd and 1000 bwpd. This field is currently under secondary recovery by waterflooding. The one hundred fifty-nine (159) producing wells are all on artificial lift. There are currently thirty (30) hydraulic wells being treated for paraffin by chemical in the field, (twenty six wells were used in the original study). Prior to this chemical program, the wells Prior to this chemical program, the wells were being treated by hot oiling. Hot oiling frequency averaged from 1–3 treatments per month. This, along with the cost of paraffin cleanouts with workover rigs, and frequent pump repairs, caused higher than normal operating costs for hydraulic wells. Therefore, a chemical treatment program was implemented. The total paraffin treating costs for wells while being hot oiled was $77,718/month. The total paraffin treatment cost for the wells after chemical treating was $61,916/month, a savings of $15,802/month or $189,624/year (See Table 1 for details). Because of the cost associated with hot oiling, an alternative had to be found. This alternative had to work well on preventing paraffin deposition, plus be cost effective. P. 585

Abstract The realisation that the use of chemical can alleviate and in some cases totally remove, problems associated with oil and gas production has been recognised for many years. The classical approach to the design and application of chemicals works well in land based systems where there is ease of accessability and long residence times are available but in offshore situations, and particularly with the 'second generation' type of operation carried out in the North Sea, these factors play an important part in the successful development and application of chemicals, Whilst wishing to concentrate on the status quo in the North Sea, it must not be forgotten that these fields are still young. A description of the likely trend in chemical requirements will be given, as exemplified by problems and solutions in other offshore locations. THE RESOLUTION OF PRODUCED WATER IN OIL EMULSION In a typical land based oilfield environment, crude being produced from individual wells is pipelined, may be many miles, into a central collecting station, where it is degassed, dehydrated and in some cases desalted into stock tank oil. It is usual for the residence time through the system from production manifold to pipeline to be large, may be several days. The resolution of emulsions and subsequent separation of the produced water takes place in three phase separators, of the gravity, heater place in three phase separators, of the gravity, heater or electrostatic type, followed by wash tanks, settling tanks and stock tanks before being pipelined. North Sea production platform designs are, through necessity, totally different. Basically the residence time through the production train is very short, usually of the order of minutes, with wellheads located on the platform itself. In fields where the crude is pipelined, two basic systems operate or are planned. Either two phase separators (gas/oil) are used with no separation of water, such that relatively large quantities of water, in some cases as much as 20 per cent., are planned to be pipelined ashore; or three separators will be utilized (gas/oil/water) with subsequent dehydration of crude on the platform, resulting in low water content crude being pipelined. On the marginal fields, or in fields where pipelines are not yet completed, crude is pumped via a short rigid and flexible line connected to a single buoy mooring (SBM) into a tanker. Because of the economics involved in shipping large quantities of water, it becomes very necessary to dehydrate the crude before loading, and as a consequence these platforms in the main make use of three phase separators. The major obstacle to overcome in the resolution and separation of the produced water offshore is the very short time available to accomplish this task. It is the case at the present time that this separation cannot be achieved without the use of chemical demulsifiers. Demulsifiers are surface-active agents which have properties which make them effective in disrupting the properties which make them effective in disrupting the effect of the natural emulsifiers present in the oil. Their initial action is at the water-oil interface. The 'skin' surrounding the tiny water droplets in the emulsion, prevents the water droplets from uniting and result in a prevents the water droplets from uniting and result in a stable emulsion. Once the demulsifier is at the water-oil interface, it is able to carry out its primary action of flocculation, A good demulsifier, concentrated at the surface of a water droplet, has a strong attraction for other droplets in the same condition. By this mechanism, large 'bunches' of drops are joined together and the oil takes on a very bright appearance since the small water droplets are no longer dispersed throughout the oil to diffuse the light. The characteristics of the demulsifier to produce the joining of droplets does not disrupt the continuity of the emulsifier film but just adds to it. If the emulsifier has certain weaknesses, this flocculation force may be sufficient to cause complete resolution of the emulsion. However, in most cases further action is necessary for the water droplets to unite and become large enough and free enough to settle out. The action of uniting water drops is called coalescence. A good demulsifier must not only be able to flocculate the water particles, but also it must be able to disrupt the films surrounding them and allow them to unite. Since the particles are all close together because of flocculation, this coalescing process results in a very rapid growth of water drop size and rapid water separation. In most crude oils, solids such as iron sulfide, silt, clay, drilling mud, paraffin, etc., complicate the demulsification process. They tend to collect at the interface and contribute significantly to emulsion stability. Often such solids are the primary stabilizing material and their removal is all that is necessary to achieve satisfactory treatment. For removal from the interface, these solids can be dispersed in the oil or they can be water-wetted and removed with the water. If dispersed in the oil, the emulsion may be treated but the solids will still remain as a contaminate in the oil.

This paper was prepared for the 48th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Las Vegas, Nev., Sept. 30-Oct. 3, 1973. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract Field and laboratory tests indicate that dissolving xanthan in water is the most troublesome problem associated with the Xanflood process. Poor dissolution produces xanthan particles which plug filters and injection wells. Caustic treatment alters the xanthan structure to produce clarified, more filterable solutions. Treatment cost is minimal and is more than offset by improved performance and lower royalties on the performance and lower royalties on the modified form of xanthan. Introduction During the past ten years, the concept of using polymeric additives in water flooding for mobility control to improve oil recovery has been vigorously explored. The results of numerous lab and field tests are available in the literature. In recent years, the use of surfactants to produce tertiary oil has provided increased incentive to develop an acceptable polymer for mobility control. Experience from surfactant field tests confirms the necessity of including a mobility control additive as previously determined in laboratory previously determined in laboratory studies. Fluid mobility is defined as a ratio of the fluid's permeability to viscosity, as shown in equation 1. For years, it was generally accepted that if one desired to lower the mobility of water, either the viscosity (1) k=----- could be increased or the permeability decreased. This reasoning is still valid; however, the advent of surfactant flooding adds a new restraint, causing a shift in the thinking concerning mobility control. Additives which lower mobility by reducing permeability do so by adsorbing on the reservoir permeability do so by adsorbing on the reservoir rock surfaces, thus reducing the size of the capillary pores through which the water must pass. The adsorption process necessarily pass. The adsorption process necessarily removes the additive from the water and hence a denuded water bank will always precede water containing the mobility control additive. This water, stripped of polymer, cannot effectively propel the surfactant bank through the reservoir. For this reason, it is desirable to use a non-adsorbing polymer to maintain mobility control at the polymer to maintain mobility control at the trailing edge of the surfactant bank where it can be effective.