Produced water composition analysis provides evidence of what geochemical reactions are taking place in the reservoir. This information can be useful for predicting and managing oilfield mineral scale resulting from brine supersaturation.
This paper presents results of a study of the produced brine compositions from three wells in a field operated in the North Sea, with geochemical modelling complementing the analysis. The findings presented in this work provide evidence of magnesium depletion and sulphate retardation in a sandstone reservoir at 130° C.
This adjusted formation water composition was then used for calculations of the injection water fraction in each of the produced water samples. The Reacting Ions Toolkit was used to plot data in a variety of formats, including ion concentration vs. ion concentration, ion concentration vs. injection water fraction and ion concentration vs. time to identify trends and to examine the extent of involvement of the various ions in geochemical reactions.
The breakthrough of sulphate, a component primarily introduced during seawater flooding, was retarded during injection water breakthrough. Observed sulphate concentrations were lower than predicted for the case of brine/brine interactions only. The implication of this sulphate reduction was lower minimum inhibitor concentration required to control scale formation and longer squeeze treatment lifetimes for the operator.
A brine/rock interaction mechanism was proposed that involves magnesium depletion and is reproduced in the reactive transport model. 1D reactive transport modelling was performed to match possible
Jordan, Myles (Nalco Champion, An Ecolab Company) | Temple, Erin (Nalco Champion, An Ecolab Company) | Sham, Anita (Nalco Champion, An Ecolab Company) | Williams, Helen (Nalco Champion, An Ecolab Company) | McCallum, Catriona (Nalco Champion, An Ecolab Company)
Inorganic scale control of sulphate and carbonate scales with polymer, phosphonate and phosphate ester scale inhibitors is well established within the oilfield service industry. The environments in which these chemical work best have been published such as vinyl sulphonates are known to be very effective for sulphate scale control in low temperatures whereas phosphonates are much less effective under these same conditions but improve at higher temperatures. What is less well understood is the potential for synergistic interaction with blends of polymers/phosphonates/phosphate esters to give reduced treatment rates, lower chemical discharge volumes and potentially lower treatment cost.
In this paper evaluation of two North Sea produced waters will be outlined. Both produced brines have a high barium sulphate scale tendency but differ in the temperature at which the fluids arrive and depart the topside process one case with a temperature of 20C and the other at 90C. Static bottle test data will be presented to evaluate the crystal growth performance of single scale inhibitors and the improvements observed when blends of these same inhibitors are applied. Select dynamic tube blocking tests data to evaluate nucleation inhibition will also be presented so that mechanism of inhibition for the blended chemicals can clearly be highlighted.
The generic inhibitor evaluated included vinyl sulphonates co polymer, phosphate esters, poly aspartic acid. In the lower temperature environment, it was observed that a vinyl sulphonate/phosphate ester blend was more effective than either of the components by themselves. Poly aspartic acid blende with phosphate ester also give a synergistic interaction but the performance of this chemical required higher treatment rates than the vinyl sulphonate co polymer blend. At higher temperature the overall treatment rates were reduced as the sulphate scale saturation values were reduced and the synergistic effects of the polymers and phosphate ester blends were evident.
As well as classic static bottle tests performance tests were carried out in the presence of reservoir solids with stirring to further understand if the interaction of the generic chemicals within the blends with suspended solids would reduce the observed performance in the solids free test solutions.
The current regulatory challenges with REACH mean that the methods outlined in this study offer the potential to reduce chemical treatment rate, cost and environmental impact by evaluating the synergistic interaction of the current range of commercially available scale inhibitors so cutting out the very high registration costs/ time delays to the market associated with new molecule development.
The practice of squeeze treatments to oil/gas production wells to prevent inorganic scale formation has been applied for over 30 years and during that period different mechanisms to retain the inhibitor chemical have been evaluated. The simple mechanism of inhibitor retention, adsorption/desorption has been complemented over the years by enhanced adsorption via mutual solvent and full precipitation of the active inhibitor onto the mineral surface of the reservoir.
Previously published studies have shown that the retention of phosphonate scale inhibitors in sandstone reservoirs can be enhanced through the addition of a ‘squeeze life enhancer’. This chemical, typically, a highly charged, low molecular weight polymer can be applied in either the preflush or overflush stage of the scale squeeze treatment. To date these studies have been conducted using low temperature (85°C) sandpack testing.
This paper details the laboratory work carried out under high temperature (146°C) field conditions to qualify the use of the squeeze life enhancer for field application.
The results of the formation damage/inhibitor return corefloods using an MEA phosphonate (EABMPA, Ethanolaminebis(Methylene Phosphonic Acid)) and polymeric squeeze life enhancer additive are presented. The coreflood results indicated that the addition of the additive within the overflush stage of the squeeze program resulted in a 19% extension of the inhibitor lifetime. The ability to extend the squeeze treatment was translated into reduced injected squeeze fluid treatment volume as injected fluid volumes was an issue for the wells being treated and therefore reduced associated oil deferment costs.
The paper will also present field data obtained from the initial two field trial treatments which were carried out in a North Sea field. The trial well had been treated more than ten times previously with the same MEA phosphonate as applied in the enhancer trial making direct comparison of the treatment performance possible. The treatment program applied to the wells resulted in no change to the clean-up rates of the treated well and no process upset during well reflow. The initial scale inhibitor returns from the field trial treatments showed the expected improvement suggested from the coreflood study.
The study brings value to the industry by providing the process to follow for qualifying and trialling a new technology in a challenging high temperature scaling environment with the results from the field supporting the carefully designed chemical selection and evaluation program.
The impact of suspended solids and dynamic conditions on sulphate scale control is well-known. Previous work examined the effect of suspended solids, along with static and turbulent conditions, on one scale inhibitor (Vs-Co). This study has focused on the challenges experienced by an operator of a chalk reservoir field, with a significant amount of carbonate solids in the system, and a high sulphate scale risk due to high barium concentration, injection seawater breakthrough, and cool topside process conditions (20°C). The initial laboratory evaluation showed that the minimum inhibitor concentration (MIC) observed increased from 50ppm to 250ppm after 24 hours (>80% efficiency) under these conditions.
A further study investigated whether a reduction in MIC could be achieved with different chemistry. Various chemicals were screened in conventional static jar tests and in stirred tests to induce turbulence incorporating mixed solids. The results showed that many of the conventional scale inhibitor chemistries, working by nucleation inhibition and crystal growth retardation, could not cope with the severe scaling conditions and were less efficient than the incumbent. However, a "novel" scale inhibitor formulation was shown to work more effectively and resulted in a significantly lower MIC than the incumbent.
Under sulphate scaling conditions (80:20 FW:SW), VS-Co recorded an MIC of 250ppm which was reduced to ≤100ppm with the novel chemical. This resulted in the opportunity for the operator to reduce their chemical dose rate and logistical costs.
This novel chemical works by a combination of nucleation inhibition and crystal growth retardation. As a result of this inhibition mechanism, other operators experiencing similar harsh sulphate scaling conditions could achieve a lower treat rate in high suspended solid loaded systems.
The practice of scale squeeze treatments to oil/gas production wells to prevent inorganic scale formation has been applied for over 30 years and during that period different mechanisms to retain the inhibitor chemical have been evaluated. Many of these studies have focused on sandstone reservoir with less extensive studies carried out on carbonate substrates. This paper details work carried out using'squeeze life enhancer' chemicals within the Preflush and Overflush stages utilising a copolymer containing a quaternary amine group to evaluate this chemicals effect on phosphonate scale inhibitor retention process. Phosphonate scale inhibitors are known to provide excellent squeeze lifetimes in carbonate reservoirs due to their strong interaction with the negatively charged formation using hydrogen ion bonding at low pH or calcium ion bridging at higher pH however with the aid of an enhancer chemical it was hoped to help the retention/release process and so provide further improved squeeze lifetimes. The location of the enhancer chemical within the squeeze process was the focus of the study. Enhancing adsorption of the scale inhibitor is not objective of this application study rather ensuring that the retained chemical is released into the flowing brine during production which is a challenge in carbonate reservoirs. Laboratory work will be presented which evaluates the effect of using a polyaspartate enhancer within either the preflush or overflush stages to extend the lifetime of a commonly applied phosphonate scale inhibitor. These tests have been carried out using pack floods at 85 C with synthetic Middle East produced water and the details of the extension in treatment life observed are correlated to the inhibitor type tested and the sequence of application of the polymer enhancer utilised. The study shows how the different functional groups within the scale inhibitor interact with the carbonate mineral surface and polymer enhancer to extend treatment lifetimes and so potentially reducing the frequency of squeeze treatments and therefore total cost of operations and it is order of application of these chemicals to the rock surface that prove to be critical to the extension observed.
Operators are collecting an abundance of produced water data that is often underused. Produced water composition data provide clues as to what geochemical reactions are taking place in the subsurface. This information can be useful for monitoring interwell connectivity, and for predicting and managing oilfield scale resulting from brine supersaturation. Coupling thermodynamic calculations with produced water analysis helps to identify geochemical effects that could impact 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 impact scale management.
Two seawater flooded chalk fields located close to each other, were selected as candidates for comparison. The temperature of one field is 130°C, while for the other it is 90°C. 6800 produced water samples from these two fields were analysed, and the compositional trends were plotted to identify deviation from conservative (non-reacting) behaviour. The compositional trends were then grouped to identify if there were common features between wells. This analysis was complemented by one dimensional reactive transport modelling to identify which reactions would be consistent with the observed trends.
Two groups of wells were identified within each reservoir based on the produced brine compositional behaviour. Each well group exhibits distinct ion trend behaviour, especially with respect to barium, calcium, strontium and magnesium concentrations – these being divalent cations that are abundant in the formation brines. The breakthrough of sulphate, a component primarily introduced during seawater flooding, varies very significantly between the two groups in each case. In one grouping the sulphate is barely retarded at all, and breaks through at seawater fractions lower than 10%. In the other grouping, however, sulphate does not break through until the seawater fraction in the produced brine exceeds 75%. This retardation of sulphate occurs most strongly in the hotter reservoir, and this may be attributed to the lower solubility of the calcium sulphate mineral anhydrite at higher temperature. The retardation of sulphate then means that barium is produced at higher concentrations, since barite precipitation in the reservoir is thus restricted due to sulphate being the limiting ion. However, some sulphate stripping does occur in the cooler reservoir, despite the higher solubility of anhydrite. Furthermore, in all cases magnesium is retarded, with some groupings exhibiting complete stripping of magnesium from the injected seawater.
The magnesium stripping behaviour 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 also contributes to the sulphate stripping through 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. Higher temperature chalk reservoirs may thus act as natural sulphate reduction plants, reducing scaling, souring risks and so operating costs of the fields.
Vazquez, Oscar (Heriot-Watt University) | Ross, Gill (Shell U.K. Ltd) | Jordan, Myles (Nalco-Champion) | Baskoro, Dionysius Angga Adhi (Heriot-Watt University) | Mackay, Eric (Heriot-Watt University) | Johnson, 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 sulphate reduction of the injected brine, flow modification to reduce water flow, damage removal by dissolvers or physically by milling or reperforating, and finally, inhibition, particularly recommended if a severe risk of sulphate scale deposition is present. Inhibition consists of the injection of a chemical which prevents the deposition of scale, either by stopping nucleation or retarding crystal growth. The inhibiting chemicals are either injected in a dedicated continuous line, or bull-headed as a batch treatment into the formation, commonly known as a scale squeeze treatment. Generally, scale squeeze treatments consists of the following stages: preflush, to condition the formation or act as a buffer to displace tubing fluids; main treatment, where the main pill of chemical is injected; overflush, to displace the chemical deep into the reservoir; followed by a shut-in stage to allow further chemical retention; finally, the well is put back in production. The well will be protected as long as the concentration of chemical in the produced brine is above a certain threshold, commonly known as minimum inhibitor concentration (MIC), usually this value is 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 above MIC.
The main purpose of this paper is to describe the automatic optimisation of squeeze treatment designs using an optimisation algorithm, in particular, using particle swarm optimisation (PSO). The algorithm provides the optimum design, which strictly speaking in terms of squeeze treatment designs, it provides the longest squeeze lifetime, although, it might not be the most efficient. To determine the most efficient design, an optimisation algorithm is used to provide an optimum design based on the following objectives: operational deployment costs, chemical cost, total injected water volume and squeeze treatment lifetime. Operational deployment costs include support vessel, pump and tank hire. There might not be a single design optimising all objectives, thus the problem becomes a multi-objective optimisation. The algorithm is capable of analysing a great number of designs, making it easy to identify the designs that are non-dominated, which provides the right amount of information to identify the most cost effective squeeze treatment design, and therefore cutting total treatment costs.
ABSTRACTThis study looks at the issues faced by operators with low temperature sandstone reservoirs of only 40°C and 54°C and the challenges these low temperatures brought which include high MIC for sulphate scale control and poor chemical retention & release properties observed during the reservoir condition corefloods. These findings will be compared and contrasted with two other higher temperature (71°C and 95°C) sandstone reservoirs where phosphonates and phosphate ester chemicals have been evaluated and deployed in the field.The findings from this detailed coreflood study and review of previous experimental/field deployed scale squeeze treatment data shows that phosphonates work very well at elevated temperatures; at and above 70°C where their stronger retention and excellent release profiles makes them a favored chemical for such treatments. However at lower temperatures these molecules are not well retained on the rock and it is the phosphate ester chemicals that are more effective and provided the longer squeeze life to its respective MIC value. Comments on the interaction/performance of polymer scale inhibitors will also be made for these low temperature conditions.The implication of these findings show that phosphate esters offer the potential for extended squeeze lifetime in the <50°C sandstone reservoirs that are being developed in Northern Norway (Barents Sea) and the shallow subsurface depth, cool reservoirs being developed in offshore Brazil.INTRODUCTIONOilfield scales are inorganic crystalline deposits that precipitate from brines present in the reservoir and production flow system.1,2,3 Precipitation occurs as the result of changes in the ionic composition, pH, pressure and temperature. The primary scale formation mechanisms and the scale resulting from these mechanisms are detailed in Table 1.Scaling Tendency and Scale Mass as a Function of TemperatureSulphate scale (particularly barite) forms as produced water (a mixture of Ba-, Sr-, Ca-rich formation water and sulphate-rich seawater) cools. Barite scale tendency increases with decreasing temperature, because barite is less soluble at lower temperatures. This is shown in Figure 1 where the barite scale tendency for a formation water (barium = 110ppm) and seawater (sulphate = 2900ppm) blend is tested between 5 and 75°C.1 The barium sulphate scaling tendency (thermodynamic driving force for precipitation) is 5-6 times higher at 5°C than at 75°C (Figure 1). The challenge of controlling scale at low temperature is therefore well-recognised.
The deployment of scale squeeze treatments in subsea horizontal wells has always presented a challenge in terms of understanding the location of injected fluids vs the location of the produced water where scale formation will occur. Over the years software packages such as Eclipse has been able to provide valuable information on the possible placement options for such wells when production logging tool (PLT) data have not been available. The development of multilateral drilling/completion technology has further complicated the placement challenges in such wells. In this paper Eclipse simulation data has been linked to SQUEEZE designs software for two subsea production wells completed with multi laterals and sliding sleeves to allow selective placement of the squeeze treatment.
The field in question consists of four reservoirs with varying barium levels (15 ppm to 320 ppm). For pressure support seawater injection has been applied from the start of field life. Prior to field start up, studies were conducted to review the order of expected injection water breakthrough for each well, the location of breakthrough along the length of the production sections, the feasibility of bullhead deployed squeezes and the implications of barium ion stripping. These issues were all assessed to generate a scale management strategy for the field.
Despite uncertainties in the original reservoir model, the order of injection water breakthrough across the field was observed to be correct and the information on placement proved very useful in building scale squeeze treatments.
The challenge of rapid injection water breakthrough in the field during its early life was addressed with development of pre-production squeeze treatments applied during new well completions. This eliminated the need to shut in wells whilst awaiting mobilisation of DSVs for treatment deployment. As the field matures, tailored scale squeeze treatments were developed for each of the 25 production wells. Over the life of the wells the squeeze designs were updated to take into account changing water rates, changing water composition and thus MIC for the squeeze chemical. The positive contribution of the downhole continual injection chemical was also shown to extend the squeeze lifetimes by allowing a lower MIC value to be used for treatment design in the production section of the wells.
Optimisation of the scale management programme has seen wells considered to be outside the scale window eliminated from the squeeze treatment campaigns, reduction in chemical volumes being applied and extended squeeze lifetime for treatments based on monthly review of well performance/water chemistry/inhibitor residuals.