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The control of inorganic scale deposition within production wells by deployment of scale squeeze treatments is a well-established method for both onshore and offshore production wells. Factors that have influenced the change from 12 to 24 months squeeze treatments include changing MIC values, rising operation expenditure related to subsea vs platform deployment costs and in all cases assessing total operational cost vs simply chemical costs alone. The implication of deferred oil associated with delayed production during pumping and post squeeze well cleanup was also considered in the design process for these wells. The paper outlines the elements of the process that should be considered/reviewed when making the decision to change from the conventional 12 months to 24 months squeeze treatment. Designs and field results from three oil producing basins, each with different cost drivers, have been used to illustrate how it is possible to maintain effective scale management through the life cycle of these production wells. 2 SPE-200701-MS
Al Kalbani, Munther Mohammed (Heriot-Watt University) | Jordan, Myles Martin (Champion X) | Mackay, Eric James (Heriot-Watt University) | Sorbie, Ken Stuart (Heriot-Watt University) | Nghiem, Long X. (Computer Modelling Group Ltd.)
Mineral scaling issues have been reported in many alkaline and Alkaline-Surfactant-Polymer (ASP) projects. The role of the
Reservoir simulation is used to model the geochemical interactions and chemical flood flow behaviour using 2D areal and vertical homogeneous and heterogeneous models. Data from the literature is used to model oil, water and rock interactions (interfacial tension, reaction rate parameters, relative permeability, chemical adsorption and polymer viscosity) for surfactant, and sodium carbonate (Na2CO3) and sodium hydroxide (NaOH) alkalis, and HPAM polymer. At the wellbore, squeeze modelling is used to investigate the volume, concentration and cost of calcite scale inhibitor for three different AS and ASP flooding options.
Results show that the
This paper gives a workflow for assessing the scaling risks for AS and ASP flooding, with crucial role played by reservoir complexity. It is therefore recommended that scaling assessment calculations following our workflow be carried out for specific AS and ASP field cases.
Operators are collecting abundant produced-water data that are often underused. Produced-water-composition data provide clues related to the geochemical reactions that are occurring in the subsurface. This information can be useful for monitoring interwell connectivity and predicting and managing oilfield scale resulting from brine supersaturation. Coupling thermodynamic calculations with produced-water analysis helps to identify geochemical effects that could affect oil recovery.
This work addresses the difference that reservoir temperature has on geochemical reactions in carbonate reservoirs by comparing data from two offshore fields and identifying the rock/brine and brine/brine reactions that will affect scale management.
Two seawater-flooded chalk fields located near each other were selected as candidates for comparison. The temperature of one field is 130°C, whereas for the other field, it is 90°C. Produced-water samples (a total of 6,800) from these two fields were analyzed, and the compositional trends were plotted to identify the deviation from conservative (nonreacting) behavior. The compositional trends were then grouped to identify if there were common features between wells. This analysis was complemented by 1D reactive-transport modeling to identify the reactions that would be consistent with the observed trends.
Two groups of wells were identified within each reservoir on the basis of the produced-brine compositional behavior. Each well group exhibits a distinct ion-trend behavior, especially with respect to barium, calcium, strontium, and magnesium concentrations—because these are divalent cations that are abundant in the formation brines. The breakthrough of sulfate, a component primarily introduced during seawater flooding, varies very significantly between the two groups in each case. In one grouping, the sulfate is barely retarded, and it breaks through at seawater fractions lower than 10%. In the other grouping, however, sulfate does not break through until the seawater fraction in the produced brine exceeds 75%. This retardation of sulfate occurs most strongly in the hotter reservoir, and this might be attributed to the lower solubility of the calcium sulfate mineral anhydrite at a higher temperature. The retardation of sulfate then means that barium is produced at higher concentrations because barite precipitation in the reservoir is thus restricted, caused by sulfate being the limiting ion. However, some sulfate stripping does occur in the cooler reservoir, despite the higher solubility of anhydrite. Furthermore, in all cases, magnesium is retarded, with some groupings exhibiting the complete stripping of magnesium from the injected seawater.
The magnesium-stripping behavior is reproduced in the reactive-transport models when calcium- and magnesium-replacement reactions are allowed. This phenomenon has been observed elsewhere in coreflood experiments, and it also contributes to the sulfate stripping through the promotion of anhydrite precipitation within the rock. This process, which is beneficial in terms of reducing the scale risk, is more pronounced at higher temperatures. Therefore, higher-temperature chalk reservoirs might act as natural sulfate-reduction plants, reducing scaling, souring risks and, thus, operating costs of the fields.
Vazquez, Oscar (Heriot Watt University ) | Ross, Gill (Chrysaor) | Jordan, Myles Martin (Nalco Champion) | Baskoro, Dionysius Angga Adhi (Heriot-Watt University) | Mackay, Eric (Heriot-Watt University) | Johnston, Clare (Nalco Champion) | Strachan, Alistair (Nalco Champion)
Oilfield-scale deposition is one of the important flow-assurance challenges facing the oil industry. There are a number of methods to mitigate oilfield scale, such as reducing sulfates in the injected brine, reducing water flow, removing damage by using dissolvers or physically by milling or reperforating, and inhibition, which is particularly recommended if a severe risk of sulfate-scale deposition is present. Inhibition consists of injecting a chemical that prevents the deposition of scale, either by stopping nucleation or by retarding crystal growth. The inhibiting chemicals are either injected in a dedicated continuous line or bullheaded as a batch treatment into the formation, commonly known as a scale-squeeze treatment. In general, scale-squeeze treatments consist of the following stages: preflush to condition the formation or act as a buffer to displace tubing fluids; the main treatment, where the main pill of chemical is injected; overflush to displace the chemical deep into the reservoir; a shut-in stage to allow further chemical retention; and placing the well back in production. The well will be protected as long as the concentration of the chemical in the produced brine is greater than a certain threshold, commonly known as minimum inhibitor concentration (MIC). This value is usually between 1 and 20 ppm. The most important factor in a squeeze-treatment design is the squeeze lifetime, which is determined by the volume of water or days of production where the chemical-return concentration is greater than the MIC.
The main purpose of this paper is to describe the automatic optimization of squeeze-treatment designs using an optimization algorithm, in particular particle-swarm optimization (PSO). The algorithm provides a number of optimal designs, which result in squeeze lifetimes close to the target. To determine the most efficient design of the optimal designs identified by the algorithm, the following objectives were considered: operational-deployment costs, chemical cost, total-injected-water volume, and squeeze-treatment lifetime. Operational-deployment costs include the support vessel, pump, and tank hire. There might not be a single design optimizing all objectives, and thus the problem becomes a multiobjective optimization. Therefore, a number of Pareto optimal solutions exist. These designs are not dominated by any other design and cannot be bettered. Calculating the Pareto is essential to identify the most efficient design (i.e., the most cost-effective design).
The injection of seawater into oil-bearing reservoirs in order to maintain reservoir pressure and improve secondary recovery is a well-established, mature operation. Moreover, the degree of risk posed by deposition of mineral scales (carbonate/sulphate) to the injection and production wells during such operations has been much studied. The current deep-water subsea developments offshore West Africa and Brazil have brought into sharp focus the need to manage scale in an effective way. In a Deepwater West African field the relatively small number of high-cost, highly productive wells, coupled with a high barium sulphate scaling tendency upon breakthrough of injection seawater meant not only was effective scale management critical to achieve high hydrocarbon recovery, but even wells at low water cuts have proven to be at sufficient risk to require early squeeze application. To provide effective scale control in these wells at low water cuts, phosphonate-based inhibitors were applied as part of the acid perforation wash and overflush stages prior to frac packing operations. The deployment of this inhibitor proved effective in controlling barium sulphate scale formation during initial water production eliminating the need to scale squeeze the wells at low water cuts (10% BS&W). To increase the volumes of scale inhibitor being deployed in the pre-production treatments and so extend the treatment lifetimes scale inhibitor was also added to the frac gel used to carry the frac sand. This paper outlines the factors that influence the suitability of pre-production treatments and present field data from treatments applied via stimulation acid, solid scale inhibitor in frac pack and scale inhibitor within fracture gel to illustrate these different methods and highlight the advantages and disadvantages of each approach. Many similar fields to the case study outlined in this publication are currently being developed in the Campos basin, Gulf of Mexico, and West Africa, and this paper is a good example of best-practice sharing from another oil basin.
Copyright 2013, Society of Petroleum Engineers This paper was prepared for presentation at the International symposium on Oilfield Chemistry held The Woodlands, Texas, USA, 8-10 April 2013. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract In many oilfields the relatively small number of high-cost, highly productive wells, coupled with a carbonate and or sulfate scaling tendency (upon waterflood breakthrough of injected seawater) requires effective scale management along with removal of near-wellbore damage in order to achieve high hydrocarbon recovery.
In a deepwater west African field, the relatively small number of high-cost, highly productive wells, coupled with a high barium sulfate scaling tendency (upon waterflood breakthrough of injected seawater) requires effective scale management along with removal of near-wellbore damage in order to achieve high hydrocarbon recovery.
The nature of the well-completion strategy in the field (frac packs for sand control) had resulted in some wells with higher-than-expected skin values owing to drilling fluid losses, residual fracture gel, fluid loss agents, and fines mobilization within the frac packs.
The paper will present how the challenges of managing impaired completions and inorganic scale forced innovation in terms of when to apply both stimulation and scale-inhibitor packages to deepwater wells. This paper will outline a novel process for non-conventional batch chemical applications where bullhead stimulation treatments have been displaced deep into the formation (> 20 ft) using a scale inhibitor overflush. Not only does this benefit the stimulation by displacing the spent acid and reagents away from the immediate wellbore area, but the combined treatment provides a cost savings with a single mobilization for the combined treatment. The paper will describe the laboratory testing that was performed to qualify the treatments. The four field treatments that were performed demonstrate how these coupled applications have proven very effective at both well stimulation/skin reduction and scale-inhibitor placement before and after seawater breakthrough. The term "squimulation" is used by the local operations team to describe this simultaneous squeeze-and-stimulation process.
Many similar fields are currently being developed in the Campos basin (Gulf of Mexico) and west Africa, and this paper presents a good example of best-practice sharing from another oil basin.
In many oilfields the relatively small number of high-cost, highly productive wells, coupled with a carbonate and or sulfate scaling tendency (upon waterflood breakthrough of injected seawater) requires effective scale management along with removal of near-wellbore damage in order to achieve high hydrocarbon recovery.
The nature of the well completion strategy in new fields such as frac packs for sand control and acid stimulation for carbonate reservoirs had resulted in some wells with higher than expected skin values due to drilling fluid losses, residual frac gel, fluid loss agents, and fines mobilization within the frac packs where applied.
The paper will present how the challenges of managing impaired completions and inorganic scale forced innovation in terms of when to apply both stimulation and scale inhibitor packages to sandstone and carbonate reservoirs. This paper will outline a novel process for non-conventional batch chemical applications where bullhead stimulation treatments have been displaced deep into the formation (>20ft) using a scale inhibitor overflush. Not only does this benefit the stimulation by displacing the spent acid and reagents away from the immediate wellbore area, but the combined treatment provides cost savings with a single mobilization for the combined treatment. The paper will describe the laboratory testing that was performed to qualify the treatments for both sandstone and an HP/HT gas condensate carbonate reservoir. The lessons learned fromcarbonate corefloodevaluationunder HT/HP conditions when appling stimulation fluids with and without scale inhibitor present in the treatment stageswill be presented.
Many similar fields are currently being developed in offshore Brazil, West Africa and Middle East, and this paper is a good example of best-practice sharing from another oil basin.
Gomes, Roberto (Petrobras S.A.) | Mackay, Eric James (Heriot-Watt U.) | Deucher, Ricardo Huntemann (Petrobras) | Bezerra, Maria Carmen Moreira (Petrobras S.A.) | Rosario, Francisca Ferreira (Nalco Company) | Jordan, Myles Martin
Evaluation of the scaling risk at production wells is generally carried out using thermodynamic prediction models. These models are generally very accurate in terms of predicting the type of scale that may form, the degree of supersaturation, and
the mass of scale that will deposit by the time the system reaches equilibrium - provided the brine composition or compositions involved are well known, and the pressure and temperatures conditions are accurately specified. However, in
performing these calculations, engineers and chemists often fail to take account of reactions occurring in the reservoir, and assume that brines reaching the production wells have not reacted in any way prior to entering the wellbore. This often leads
to a significant overestimate of the scaling risk.
The work presented in this paper addresses this issue by studying data from various fields to identify what can be learnt from the produced brine compositions. A new technique to estimate the range of scaling tendencies that takes account of
reservoir precipitation is developed, and the results are displayed in a 3D response surface. This is illustrated for barium sulphate scaling tendency, accounting for different levels of ion stripping.
In order to calibrate some simulation parameters, and to identify the more important equations that should be inserted in the reservoir simulation, studies were performed based on the observed data. Different reservoir simulations were used and
compared, with a focus on scale management to identify positive and negative aspects of each one.
This work has identified that in fields with reservoir temperatures above 120°C and calcium concentrations above 7000 mg/l, significant sulphate stripping occurs due to anhydrite precipitation. This effect is increased where ion exchange
leads to a reduction in magnesium and an increase in calcium concentration as the injected brine is displaced through the reservoir.
Oilfield scale formation represents a very significant flow assurance challenge to the oil and gas industry, with increasing water production worldwide and higher oil prices. Scale Inhibitor (SI) squeeze treatment is the most widespread method to
combat downhole scaling. In order to predict SI squeeze treatments accurately for further optimisation, it is necessary to simulate the SI retention in the formation, which may be described by pseudo-adsorption isotherms. While these are often
derived from core flood experiments, sometimes they are not appropriate for modelling well treatments because the core tests on which they are based cannot fully represent field scale processes. In practice, the parameters of an analytic form of the isotherm equation are modified by trial and error by an experienced practitioner until a match is obtained between the prediction and the return profile of the first treatment in the field.
The main purpose of this paper is to present a Stochastic Hill Climbing Algorithm for automatic isotherm derivation. The performance of the algorithm was evaluated using data from three field cases. Two success criteria were defined: firstly,
ability to match a single historical treatment and secondly, ability to predict subsequent successive treatments. To test for the second criterion, a candidate isotherm was derived from the first treatment in a well that was treated with the same chemical package on consecutive occasions, and then the predictions using the suggested solution were compared with the observed scale inhibitor concentration return profiles from the subsequent treatments. In all the calculations, performance of the isotherms suggested by the Hill Climbing algorithm and isotherms derived by trial and error were compared. The results demonstrate that the Hill Climber Algorithm is a very effective technique for deriving an isotherm to enable accurate modelling of scale inhibitor squeeze treatments.