Squeeze Treatments Research Articles

Scale Control Within the North Sea Chalk/Limestone Reservoirs—The Challenge of Understanding and Optimizing Chemical-Placement Methods and Retention Mechanisms: Laboratory to Field

SummaryThe scale-control challenges for two North Sea carbonate reservoirs are reviewed in this paper. While carbonate reservoirs are not the largest source of hydrocarbons within the North Sea, they are very significant on a global basis.The mechanism of scale-inhibitor chemical retention observed for phosphonate, polymer, and vinyl sulfonate copolymer (VS-Co) inhibitors on carbonate-reservoir substrates is outlined. Chemical placement represents the most significant technical challenge when performing scale-inhibitor squeeze treatments into fractured chalk reservoirs. Examples from more than 50 field treatments applied in reservoirs E and V, in which both phosphonate and VS-Co chemicals have been deployed, are used to illustrate the difference in chemical retention observed in laboratory evaluations. The laboratory studies demonstrated clear potential for significant extension in treatment lifetime by changing from a phos-phonate to a VS-Co-based scale inhibitor. The selection and qualification of chemical-placement systems for deployment of inhibitors in fractured carbonate reservoirs are also outlined. To this end, novel technologies to enhance conventional scale-inhibitor-chemical placement are vital to economic success during waterflood projects.

Integrated Risk Analysis for Scale Management in Deepwater Developments

SummaryOwing to the increased cost of scale management in subsea developments, compared with platform or onshore fields, and because of the more-limited opportunities for interventions, it is becoming increasingly important to carry out a risk-analysis process for scale management as early as possible in the field-development plan. This process involves identifying the potential scale risks and analyzing and comparing the options available for managing those risks.This paper discusses how this risk-analysis process should be carried out, with a strong emphasis on the need to integrate all the available production-chemistry and reservoir-engineering data. To demonstrate this process, an example is used from a development complex that lies in water depths greater than 400 m (greater than 1,300 ft) offshore west Africa. The process involves the following steps:Analysis of available brine samples to identify maximum scaling potential. Laboratory testing of available scale inhibitors to identify chemistry best suited to this system. Study of analog fields to identify scaling risks in these fields, and how these risks have been managed, with implications for fields currently being studied. Modification of full-field reservoir-simulation model to predict seawater breakthrough and duration of seawater production to identify when and for how long the wells would require to be treated to control scale and how much inhibitor would be needed. This process involves using flow profiles derived from the reservoir-simulation model and applying them in a near-well squeeze simulator to predict treatment performance in terms of time taken for return concentrations to decrease to the minimum inhibitor concentration determined by laboratory studies. Well-by-well analysis of predicted seawater-production profiles and total-water production rates to identify the potential for correct placement of inhibitor by bullhead treatments in zones at risk of scale deposition. Modification of reservoir model to study the impact of in-situ scale deposition on brine chemistry at the production wells and the revision of requirements for inhibitor squeeze treatments. Economic analysis of options available for scale management comparing sulfate reduction to inhibitor squeezing on the basis of the treatment specifications identified above.The result of this process in the reservoirs in question, which have a moderate-to-severe scaling tendency, has been to demonstrate that inhibitor placement by bullheading would result in satisfactory placement for all wells. If the assumption is made that no scale deposition takes place in the reservoir, then sulfate reduction becomes a viable option, owing to the requirement of regular treatments and relatively high chemical concentrations. However, taking into account cation losses, owing to scale deposition deep within the reservoir, the requirements for chemical treatments reduce and squeezing becomes the preferred option. From the simulation models, differences between the reservoirs concerned, in terms of the contribution aquifer waters make to scale control, were identified with some wells at much higher risk than others owing to the volumes of potentially scaling brines that are expected to be produced.This paper clearly demonstrates that a cross-discipline approach using reservoir engineering, production chemistry, and completion engineering can lead to a more-complete assessment of the scale risk and the correct economic selection of the control program.

A Novel Nonaqueous-Inhibitor Squeeze Package for a Water-Sensitive HP/HT Reservoir

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 87435, "The Challenge of Squeezing a Water-Sensitive HP/HT Reservoir - Lab and Field Experiences With a Novel Nonaqueous Inhibitor/Squeeze Enhancer Package," by Ping Chen, SPE, Thomas Hagen, Hugh Bourne, SPE, and Katherine Turner, SPE, Champion Servo, and Frank Moller Nielsen, Mette Rian, and Andreas Haldoupis, SPE, Statoil, prepared for the 2004 SPE International Symposium on Oilfield Scale, Aberdeen, 26-27 May. Downhole scale control in Statoil’s Åsgard field presents a particularly severe challenge. The field is producing from low-permeability formations with a high drawdown through subsea templates. System pressure and temperature changes experienced during production promote formation of carbonate scales, which have been identified in the near-wellbore area and perforated intervals. The high formation temperature and pressure (165°C and 500 bar, respectively) and high chlorite content coupled with the water-sensitive nature of some of the formations create a challenging environment for downhole scale treatments. Introduction Oilfield scale is a water-related problem and often is associated with the production of water in the field. The severity of the problem and the most cost-effective solution are dependent on the field operating conditions. A number of remedial and proactive scale-management tools are available, including chemical- and nonchemical-based options. It is commonplace to prevent scale formation by injecting a chemical inhibitor continuously and/or by periodic squeeze treatments into the reservoir, depending on the location of the scale deposit. Åsgard is within the Haltenbanken group in an environmentally sensitive area because of its plentiful fish reserves, and licensees are faced with stringent guidelines for chemical use. The field comprises the Smørbukk, Smørbukk Sør, and Midgard fields. Åsgard is considered to be among the world’s largest subsea developments, producing oil, condensate, and gas through two production facilities (Åsgard A and B) from 10 reservoirs spread over a 60×20-km area. The production facilities include 50 wells in 16 subsea templates tied together by 300 km of 10- and 20-in. flowlines. Carbonate-scale deposition has been identified in the near-wellbore area and in tubing for some of the wells in Åsgard. Production conditions in the Smørbukk field present the greatest challenge for carbonate-scale control. All Smørbukk producers are commingled, with production from several formations. The high pressure and high temperature (HP/HT) and the environmental requirements limit the choice of chemistry that can be used. In addition, the field is producing from low-permeability formations with a high drawdown through subsea templates, which increases intervention complexity and the potential for and impact of formation damage. Some of the Åsgard formations are rich in fines, and additional precautions are required when deploying fluids into the near-wellbore area to minimize fines mobilization.

Kinetic Study of Scale Inhibitor Precipitation in Squeeze Treatment

Oilfield formation damage by scale formation can occur when two incompatible brine streams are mixed. A common method for preventing scale formation is the use of chemical scale inhibitors such as aminotri(methylene phosphonic acid) (ATMP). Scale inhibitors are injected and retained in the reservoir by adsorption and/or precipitation. The induction time, the period between the establishment of supersaturation and the detection of a new phase, is a measure of the ability of an inhibitor solution to remain in the metastable state. As a result, long induction times allow transport of inhibitor fluids into the near-wellbore regions without precipitation of the scale inhibitor and subsequent formation damage. In this study, an induction time model is applied to precipitation of the inhibitor (ATMP) with Ca2+ ions. The nucleation kinetics can be described by classical nucleation theory. Solution equilibrium was calculated by accounting for inhibitor dissociation and cation−inhibitor complexing as a function of ...

Factors Affecting Scale Inhibitor Retention in Carbonate-Rich Formation During Squeeze Treatment

SummarySignificant progress has been made toward developing a quantitative understanding of the inhibitor/rock interaction. In this study, four common oil field inhibitors (three phosphonates and one polyacrylate) are compared using carbonate-rich formation material. In addition to calcite (CaCO3) in the reservoir rock, several calcium inhibitor (Inh) solid phases are also important. Two reactions are central to the inhibitor retention in carbonate-rich formation: first, reduction of calcite dissolution because of surface poisoning by the Ca-Inh coating; and second, precipitation of Ca-Inh solid with either low Ca or high Ca stoichiometry. For NTMP, an acidic Ca-NTMP salt is formed at a low-pH environment. In addition, two crystalline Ca-NTMP phases and an amorphous Ca-NTMP salt may form, depending on the aquatic environment. Quantitative relationships between types of inhibitors, inhibitor acidity and concentration, and kinetics of calcite dissolution and calciumphosphonate precipitation are developed. Consequences of the observations on squeeze design and scale inhibition will be discussed.

Predicting Brine Mixing Deep Within the Reservoir and Its Impact on Scale Control in Marginal and Deepwater Developments

SummarySulphate scale deposition is a common problem in hydrocarbon reservoirs in which injection seawater that is rich in sulphate mixes with formation brines that are rich in barium, strontium, and calcium. Deposition of these scales can cause significant production impairment if it occurs within zones near the production wellbores. To control scale deposition in the near-wellbore region of a reservoir, scale squeeze treatments are commonly deployed. In cases in which scale severity is very high, removal of sulphate ions from the injection water is an alternative scale-control strategy. Both these mitigation methods have associated capital (CAPEX) (e.g., desulphation plant) and operating expenditures (OPEX) (e.g., scale squeeze treatments).To assess the severity of the problem in new fields, thermodynamic calculations typically are performed to calculate the mass of scale that will form. Until recently, little work has been carried out to identify the location of scale formation within the reservoir. In this paper, field data and flow simulations from three North Sea fields are presented to show that scale formation can, in fact, occur deep within the reservoir and can have a negligible negative impact on oil production in the near-wellbore region.Evidence is presented from these North Sea fields that shows the evolution of the brine chemistry as seawater breakthrough occurs and as squeeze treatments are applied. The evidence from the produced brine chemistry is linked to flow calculations for these fields to show that in some systems scale is depositing deep within the reservoir, reducing the potential for damage in the near-production wellbore region. The extent and impact of the deposition varies throughout the reservoir and can be quantified. Modeling brine mixing and stripping of the scaling ions before the fluids reach the production wellbore has a significant impact on the economic assessment of marginal fields and deepwater developments. In such fields, the technical challenge and cost (CAPEX/OPEX) of scale control might make development uneconomical. This paper outlines the data requirements and methodology used to allow such an assessment to be made.

Predicting in Situ Sulphate Scale Deposition and the Impact on Produced Ion Concentrations

Simulation models may be used to predict not only where the mixing of incompatible brines occurs in water-flooded reservoirs, but also the impact of in situ deposition on scaling ion concentrations in and around the production wellbore. The location of maximum sulphate scale deposition and the resulting brine compositions at the production well are calculated for a range of sensitivities, including reservoir properties (layered, homogenous, aquifer), well geometry (location and orientation within field and with respect to other wells and the aquifer), and various production scenarios (desulphation and squeeze treatment). In conventional systems with no aquifer, it is demonstrated that maximum scale deposition occurs within or in the immediate vicinity of the production wellbore, and therefore low produced cation concentrations would indicate that squeeze treatments have not been successful. In systems where water injection is into the aquifer, low cation concentrations may result from deposition deeper within the reservoir. Maximum scale dropout still occurs as the fluids approach the production well, but may be sufficiently far from the wellbore not to have any major impact on productivity, or to be affected by squeeze treatments. However, sufficient concentrations of scaling ions are still delivered to the production well to necessitate squeeze treatments, although using lower volumes of inhibitor. Once cation concentrations have been reduced by deposition deep within the reservoir, it is predicted that they will never pick up again. This paper also assesses the impact of desulphation and produced water re-injection on scale deposition in the reservoir, and the need to protect injection and/or production wells is discussed.

Modeling In-Situ Scale Deposition: The Impact of Reservoir and Well Geometries and Kinetic Reaction Rates

Summary Previous work has demonstrated how and where the mixing of incompatible brines occurs in waterflooded reservoirs and what the impact on scale prevention strategies is in terms of timing and placing squeeze treatments. This paper extends this work by modeling the resulting in-situ deposition process. The location of maximum scale deposition and the resulting brine compositions at the production well are calculated for a range of sensitivities, including reservoir geometry (1D, 2D areal and vertical, and 3D), well geometry (location and orientation within the field and with respect to other wells and the aquifer), and the reaction rate (ranging from no precipitation to equilibrium). In conventional systems with no aquifer, it is demonstrated that maximum scale deposition occurs in the immediate vicinity of the production wellbore; therefore, low produced-cation concentrations indicate inadequate squeeze treatments. In systems in which water injection is into the aquifer, low cation concentrations may also result from deposition deeper within the reservoir. Maximum scale dropout still occurs as the fluids approach the production well but is sufficiently far from the wellbore to be unaffected by squeeze treatments or to have any major impact on productivity. The reaction rate is critical in determining the amount of scale deposition; however, even under equilibrium conditions, sufficient concentrations of scaling ions are delivered to the production well to necessitate squeezing it but with lower inhibitor volumes. Once cation concentrations have been reduced, it is predicted that they will never increase again. This paper also discusses some of the limitations of modeling such systems, including determination of kinetic reaction rates, mixing zone size, and impact on permeability. Although the thermodynamics are fairly well understood, the kinetics are much more difficult. The size of the mixing zone is affected by numerical dispersion, and computationally intensive techniques are required to overcome this problem. Previous experience shows that formation damage factors are very difficult to extrapolate from coreflood data because there is a great difference between the dimensions of the mixing zone in the reservoir and the core plug.

The Development and Application of a Novel Scale Inhibitor Deployment System

SummaryWater-in-oil emulsions have been developed that have been shown to be a credible means of deploying scale inhibitors in a nonaqueous medium. Furthermore, the use of slowly degrading emulsion systems provides a means of trapping the scale inhibitor within porous media and allowing the subsequent controlled release of the chemical. This has been demonstrated with sandpack and core-flood experiments in which the inhibitor's lifetime, as measured by pore volumes of brine eluted to a given inhibitor concentration, has been extended by up to (and possibly beyond) four times compared with the base-case, nonemulsified product. No permeability damage has been observed for the emulsion systems. The use of emulsion droplets to provide chemical reservoirs within the formation also considerably reduces the nonretained chemical waste observed with conventional squeeze treatments. The nonaqueous nature of the emulsion system allows the potential ingress of the scale inhibitor into parts of the reservoir normally denied access to an aqueous-based formulation, so it can improve contact between the scale inhibitor and the reservoir fluids on production. Furthermore, the whole treatment can be nonaqueous, allowing oil continuity to be maintained during the treatment and affording rapid well cleanup post-treatment. The efficacy of the emulsion system is illustrated with the results of a successful field trial performed on the Forties field in the U.K. sector of the North Sea.

Deployment of a Scale Squeeze Enhancer and Oil-Soluble Scale Inhibitor To Avoid Oil Production Losses in Low Water-Cut Well

Summary This paper outlines the development of an effective treatment strategy for production wells that suffered significant performance impairment at water cuts of less than 5% caused by carbonate scale deposited within the electrical submersible pumps (ESPs). These Alaskan production wells had been treated for a couple of years with aqueous-based scale-inhibitor squeezes. Many of these treatments resulted in a significant reduction (10 to 20%) in the oil production rate following the squeeze. The damage mechanism was investigated by coreflooding and was revealed to be a combination of water block and relative permeability effects. Following the coreflood damage investigation, a second study was undertaken to investigate a chemical treatment to remove the damage already present within the near wellbore and to prevent further deposition of scale. The result of this test program was the development of a treatment strategy that used a solvent package followed by an oil-soluble scale inhibitor. Field results of this type of treatment suggest that the wells treated with this chemical system did not suffer any reduction in the oil production rate and were effectively protected from carbonate scale. Wells that had been damaged by the previous aqueous treatments could be stimulated, and the lost oil production could be recovered. Reference is also made to the development of improved, aqueous-based squeeze treatments for the treatment of higher water-cut wells.

Atomistic Simulations of Corrosion Inhibitors Adsorbed on Calcite Surfaces I. Force field Parameters for Calcite

We report a new force field for calcite suitable to study scale formation and squeeze treatments for oil field applications. The force field reproduces the cell parameters, density, and the compressibility of the calcite crystal as well as the enthalpy of immersion of various solvents. Surface energetics for the various surfaces of interest are predicted.

Removal of Asphalt Deposits by Cosolvent Squeeze: Mechanisms and Screening

Summary Performance improvement of usual solvents for asphalt deposits was investigated in an effort to optimize squeeze treatments of formations damaged with asphaltenes. The approach adopted for increasing the solvent power for asphaltenes of such solvents as xylene was to design solvent mixtures with a polarity adjusted to specific chemical features of asphaltenes contained in the crude oil considered. For that purpose, Hansen's theory was used as a guide in defining the composition of cosolvents suitable for asphaltenes. In addition, to increase solvency and to disperse asphaltenes, proper additives were used as a means to create hydrogen bonding with the heteroatoms present in the asphaltene chemical structure or to modify the intermolecular interactions involved in asphaltene aggregation. Laboratory screening of cosolvents involved four types of tests that were based on the physical/chemical mechanisms deemed predominant in a squeeze operation (i.e., the solvency of asphaltenes, the ability to desorb the asphaltenes adsorbed onto minerals making up the reservoir rock, and the capacity to maintain dispersion of the asphaltenes within the organic phase). Several cosolvents, with a few percent commercial chemicals containing an alcohol or amine functional group in their molecules, were found to exhibit the required properties vs. either solid extracted asphaltenes or well deposits. The final cosolvent efficiency was checked at reservoir temperature in squeeze experiments carried out in core samples. After a permeability damage occurred during asphaltenic crude oil flow, the remedial effects of squeezes of different cosolvents were evaluated. Several examples illustrate the improvement gained with the designed cosolvents and additives in restoring part of the oil permeability and in reducing the in-situ asphaltene deposition accompanying crude oil flow through core samples.

Modelling Scale Inhibitor Squeeze Treatments in High Crossflow Horizontal Wells

Abstract Modeling scale inhibitor treatments in horizontal wells is emerging as an important field of research due to the need to reduce the cost of treating wells that may be thousands of feet long. Simulation studies performed using recently developed modeling tools have led to recommendations that have reduced the risk of chemical upsets at the wellhead and extended squeeze lifetimes downhole. However, as an increasing number of "problem wells," such as high crossflow wells, need to be treated to prevent scale formation, these models have to be adapted to enable them to capture the complex range of properties that make these systems so problematic. Diverter technology is being developed to enable optimal placement of chemical inhibitor, but to study the impact of the diverter on the squeeze performance, the fluid flow properties in the near-wellbore region must be modeled accurately. This is done by using a full-field reservoir simulation model that includes sufficient detail in the near-well formation not only to capture the fluid flows, but also to model accurately the chemical placement and recovery. The model can assess the impact of various placement strategies, as well as assist in determining the optimal fluid and chemical volumes. A case study from the North Sea where a gel diverter was selected to assist inhibitor placement is presented. The study demonstrates the types of calculation that can be made, and what information can be usefully supplied to the field engineer designing squeeze treatments. Introduction Mineral scale deposition in the near-wellbore area and tubular is a problem encountered in all types of production wells in the period following water breakthrough(1–3). Squeezing scale inhibitors into the near-wellbore formation is a strategy that has been used to successfully protect many hundreds of vertical wells(4–7). The squeeze treatment involves injection and over flush of a water-soluble chemical inhibitor that adsorbs onto the rock surface during a post-squeeze shut-in period. When the well is returned to production, the inhibitor slowly desorbs from the rock surface into the flowing water phase, and enters the well. Provided an appropriate choice of inhibitor is made, and provided it has been placed correctly, scaling tendencies in the produced water will be inhibited by the returning chemical for as long as its concentration remains above a threshold value(6,8). This Minimum Inhibitor Concentration (MIC) is routinely determined from laboratory Measurements(9). Modeling techniques have been developed to assist the design of squeeze treatments(10–14). Use of these models for optimizing treatments in vertical wells has proved very successful, and simulations are often performed as a matter of routine when designing treatments. However, the long production intervals associated with horizontal and deviated wells, along with the possibility of extended production at high water cuts, can make the design of squeeze treatments in these wells much more difficult. In addition, the increased capital investments and higher production rates associated with horizontal wells mean the risk of scale forming in the wellbore is even less tolerable than for conventional wells.

Modeling Scale-Inhibitor Treatments in Horizontal Wells: Application to the Alba Field

Summary Many horizontal wells produce both oil and brine for an extended period of time and, therefore, in many cases the problem of mineral scale deposition must be solved. Scale management in long horizontal wells faces several challenges, a major one being the correct placement of the scale inhibitor slug in the formation. Accurate placement is required to ensure that vulnerable well sectors are treated, without wasting chemical in the protection of zones which will not cut water during the lifetime of the squeeze treatment. This paper presents results from a novel nearwellbore simulator (assist2), which is used to model scale inhibitor treatments in horizontal wells. A technique for modeling such treatments has been developed which gives an improved understanding of where the chemical will be placed under different injection strategies, and how the placement will impact the squeeze life. It also allows the engineer to assess the impact of varying such parameters as inhibitor slug volume and concentration, overflush volume, injection rate, etc. Different inhibitor chemicals can be compared for their performance under the given reservoir conditions. This technique has been applied to model a squeeze treatment in a horizontal well where good production data are available. Connection oil and water flow rates, calculated by a full-field simulation model, have been matched by assist2. Various treatment designs were tested to assess the impact of the controllable parameters listed above. Findings enabled a treatment to be specified that was predicted to increase the squeeze lifetime without increasing the volume of chemical required. This modeled application strategy will also reduce the initial inhibitor concentration spike in the return curve. The performance of various chemicals under reservoir flow conditions was modeled, with a clear best choice emerging from these studies. Based on the findings of this modeling work, recommendations were made for a squeeze treatment, which were implemented, and the resulting field data are presented.

Novel Wax-Diverter Technology Allows Successful Scale-Inhibitor Squeeze Treatment in a Subsea Horizontal Well

Summary In this article we present field results from two scale squeeze treatments carried out on the same subsea horizontal well from the Strathspey field in the North Sea. The initial squeeze was a bullhead application of phosphonate scale inhibitor to control a sulfate scale problem in a horizontal well. Ten months after the initial treatment a second bullhead squeeze treatment was applied in two stages. This latter utilized a thermally degraded pelleted wax diverter to temporarily impair the injectivity in the heel region of the horizontal well thus allowing propagation of the second stage of the squeeze treatment into the midsection of the horizontal well. In this article we show the significance of production logging tool data to evaluate the location of deposited scale and water production prior to a squeeze treatment. These data were used to design a novel two stage squeeze treatment in which an initial squeeze slug was applied to the heel region followed by application of a pelleted thermally degraded wax diverter to prevent further loss of scale inhibitor to the heel region. The action of the wax diverter allowed a second scale inhibitor slug to be placed further along the horizontal section of the well. Details of the diverter selection and the squeeze design strategy implemented in this squeeze treatment will be presented. During the field treatment, physical (downhole pressure and temperature) data and chemical (nonradioactive tracers, inhibitor and ion concentrations) data were recorded. These data will be used to indicate the success of the diversion treatment by a comparison with the first squeeze applied to the same well 10 months previously. This is the first successful application of a thermally degraded wax diverter to a subsea horizontal well in the North Sea basin. The well was successfully treated with no process upset during flowback and no decline in well production while allowing the well bore to be protected from continued sulfate scale formation. In this article it is clearly shown that with the correct selection of both the scale inhibitor and diverter agent together with ulitization of all available information relating to the reservoir, it is possible to squeeze scale inhibitors into subsea horizontal wells without the need for intervention by expensive coiled tubing from a diving support vessel.

Advantages of a New Chemical Delivery System for Fractured and Gravel- Packed Wells

Summary The deposition of scale, such as carbonates and sulphates, in production facilities represents a serious operational problem that can result in significant well productivity decline. Current scale control strategies can involve significant capital and operational expenditure. Development work, involving laboratory testing and a field trial, has demonstrated the technical benefits of a revolutionary method of downhole scale inhibitor delivery that can prevent scale deposition for a significant proportion of a well's lifetime. The method involves the slow release of scale inhibitor from porous proppants. Economic analysis indicates that significant benefits can be derived for a variety of field development and well completion types. The greatest economic benefits would be realized for subsea and minimum facility installations with high intervention costs, where squeeze delivery of inhibitor or mechanical workover are used for scale control. In addition, major economic benefits can be realized for horizontal wells with unfavorable pressure regimes, multilateral-type completions, multiple fractured wells, and many conventional completion types. The new chemical delivery method offers cost reduction through reduced deferred oil, efficiency of chemical usage, and fewer workovers using coil tubing and intervention vessels. Economic analysis has indicated that for some conventional and advanced well types, fracturing a well and deploying proppant impregnated with scale inhibitor, is economically preferable to a conventional strategy of squeeze treatment in an unfractured well. An additional economic benefit of proppant impregnated with scale inhibitor is increased well productivity. The benefit is derived from the combined effect of improved gel breaking, and scale inhibition during well cleanup. This has been demonstrated in laboratory testing and would appear to be confirmed by field observations. A further benefit of applying scale inhibitor as chemically impregnated proppant is the immediate treatment of produced water when water breakthrough occurs. This feature avoids the formation damage that can occur before squeeze treatment mobilization. In addition, for some applications involving large fractures there is the potential for lifetime well treatment. This paper describes the laboratory work, the field trial, and the economic benefits of the new product.

PHASE BEHAVIOUR OF PHOSPHINOPOLYACRYLATE SCALES INHIBITOR

The influence of the Ca++ and inhibitor concentrations, pH, and temperature on the phase behaviour and precipitation yield of a phosphinopolyacrylate scale inhibitor, PPAA, has been studied. The results are interpreted in terms of the chemical processes governing PPAA-Ca++ complexation, and evidence for the role of inhibitor molecular weight in determining the degree of precipitation is produced. Comparative adsorption and precipitation squeezes, carried out in sandpacks, demonstrate that significant enhancement of the treatment lifetime can be achieved when conditions giving extensive inhibitor precipitation are used. The sandpack experiments and dissolution studies on the precipitated inhibitor both suggest strongly that kinetic phenomena influence the return level of inhibitor in the field. Together these studies point the way to approaches for optimising inhibitor precipitation squeeze treatments in order to control scale deposition in petroleum reservoirs.

Scale Inhibitor Squeeze Strategies In Horizontal Wells

Abstract Much attention has been given to the drilling, completion and initial production stages of horizontal wells. The advantages of using horizontal well technology is well documented and many successful field cases-in terms of well productivity-have been reported. Much less attention has been given to some of the production problemswhich may arise when such wells start to produce water. In particular, there are a range of specific production chemistry issues which have not been widely discussed in the industry literature. The main reason for this is that, to date, there is very little operationalexperience with such problems. In this paper, we consider the problem of carrying out scale inhibitor squeeze treatments in horizontal wells. If carbonate or sulphate scale formation occurs in a water producing horizontal well, we anticipate that the treatment strategy will be rather different from that which would commonly be applied in a vertical well. The authors are not aware of very much field experience which can be called upon for this type of treatment. We have therefore taken a conceptual design approach which tries to anticipate the problem and to plan ahead for its solution. A simulation and modelling study is presented in which various scale inhibitor treatment strategies are examined with a view to determining the main factors which affect this process in a horizontal well. We tackle a number of important questions which will face the industry as scaling problems are encountered in horizontal wells. We present this work as a preliminary study which tries to highlight some of the issues, problems and questions which will arise in the future when more horizontal wells start to operate at higher watercuts. The objective is to raise these issues at this stage in order to stimulate some discussion within the industry about how scaling problems in horizontal wells will be solved, possibly by using squeeze technology. We do not solve all of the problems which we raise but a number of points emerge from our study which we present as a preliminary assessment of this problem. Introduction More and more current field developments are employing horizontal well technology in order to improve reservoir sweep efficiency, raise well productivity and to generally improve project economics(1). Indeed, many field developments would not be possible without the use of horizontal wells. The states of development of horizontal well technology might be broadly classified into the following three categories:drilling and completion,reservoir characterization and engineering andproduction operations and well intervention. This order also represents the industry's decreasing level of experience, and hence knowledge, with the third category being some way behind the others(2). How much one might need to engage in the third area dealing with water production and stimulation depends on the specific company's view on how they wish to use horizontal wells. If no period of post-water breakthrough is envisioned, or if this period represents the abandonment time for that horizontal well, then clearly this matter is not important.

Solubility and phase behavior of polyacrylate scale inhibitors

The phase behavior and precipitation yield of a commercial phosphino-polyacrylate inhibitor (PPAA) widely employed in precipitation squeeze treatments have been characterized as a function of temperature, pH, and the Ca 2+ and PPAA concentrations. Contrary to expectations, over a range of conditions the yield of phase-separated PPAA was found to be less than 50% and sometimes as low as 5%. Studies on a sample of isolated precipitate show that it has significant solubility even in brines with high Ca 2+ concentration. Ca 2+-induced fractionation of the polymeric inhibitor by molecular weight has been identified as the mechanism responsible for both the observed precipitation and re-dissolution behavior. Implications of these results for the optimization of precipitation squeeze treatments are discussed.

Cost-Effective Design of Scale-Inhibitor Squeeze Treatments Using a Mathematical Model

Summary Scale formation and deposition in production facilities is a challenging problem faced by the oil industry. Their deposition leads to operational problems, safety hazards, and an overall decrease in production efficiency. Downhole scale-inhibitor squeeze treatments provide the most common and effective means of preventing the formation of oilfield scale deposits. This paper presents an analysis and design study of field-inhibitor squeeze treatments. A mathematical model was used to simulate inhibitor-squeeze return data from several Saudi Aramco wells. A wide range of sensitivities in squeeze treatments were investigated, including inhibitor concentration, inhibitor volume, overflush size, and shut-in time. An optimization of the squeeze injection parameters was carried out with the numerical simulator. This optimization was based on squeeze performance as well as on economic criteria. The results indicate that the optimized treatment strategy is very well-specific and depends on the water production rates and operational parameters, like the scale-inhibitor concentration and volume and the amount of overflush. Recommendations are made for optimizing (in terms of cost effectiveness) the squeeze-treatment design.