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The prediction of pH-dependent scales such as carbonates and sulfides presents unique challenges because their formation is strongly related to the three phase partitioning of the acid gases (CO2 and H2S). A rigorous procedure is required to ensure proper modelling of the hydrocarbon phases, in order to derive the correct data input for the software from available field data. Using this input, reliable scale prediction calculations may then be run using either integrated or separate PVT and scale prediction software. Although some carbonate scale prediction methods have been published in the past, these methods are field and software specific, and they do not provide a general procedure for carbonate and sulfide scale predictions in oil and gas wells. Operators also have in-house proprietary procedures, but these are not publicly available and hence cannot be used or critically reviewed by the wider upstream chemistry community.
This work presents an improved version of the original Heriot-Watt scale prediction workflow previously published in 2017 (
The workflow is built on three general calculation blocks which apply to all field scenarios, as follows: 1. defining a total PVT feed; 2. modelling the water chemistry leaving the reservoir; 3. running scale prediction calculations throughout the system. After describing the general carbonate and sulfide scale prediction procedure in details, this paper also looks into the specific calculation steps required in different scenarios for variable oil type, sample availability (topside vs downhole), software choice (integrated vs separate PVT and aqueous phase models), EOR, reservoir souring, artificial lift, and HP/HT/HS.
This is a truly general approach to carbonate and sulfide scale predictions which the authors hope will provide a widely available, useful tool to anyone performing field prediction studies for pH-dependent scales. In addition, a worked example is presented in
Al Bahri, Mohammed Said (Heriot-Watt University) | Vazquez, Oscar (Heriot-Watt University) | Beteta, Alan (Heriot-Watt University) | Al Kalbani, Munther Mohammed (Heriot-Watt University) | Mackay, Eric James (Heriot-Watt University)
It is common that a large volume of hydrocarbons remained unrecovered after primary and secondary recovery. Enhanced Oil Recovery (EOR), as tertiary recovery, plays a key role in recovering additional volumes of hydrocarbons. However, there is little work in the literature on the impact of different EOR mechanisms on the flow behaviour of formation/injected brines and scaling tendencies. The objective of this manuscript is to investigate, by the means of reservoir simulation, the impact of different EOR techniques, namely low salinity waterflooding (LSW), polymer flooding and Thermally Activated Polymer (TAP), for in-depth conformance control, on oil recovery and BaSO4 scale deposition.
A reactive transport reservoir simulator was used to evaluate the impact of three EOR techniques in the mixing profiles of injected seawater and formation brine, resulting in the precipitation reaction of BaSO4, due to the incompatible mixing of formation and injected brines. Three two-dimensional models were considered, a homogeneous and heterogeneous areal model to compare polymer flooding and LSW; and a vertical heterogeneous model to analyse the effect of TAP.
Results show that LSW delays and reduces the risk of BaSO4 scale deposition at the producer, due to the fact that the concentration of injected SO42- is significantly lower than full sulphate injection seawater. However, LSW results in longer co-production period of Ba2+ and SO42- ions, due to the fact that Ba2+ stripping is reduced because of the scale precipitation within the reservoir is reduced. Polymer flooding improves the sweep displacement, which delays the onset of scale formation, shortens the co-production period of the scaling ions at the producer and reduces the amount of water produced, hence, reducing the scale risk. TAP injection results in the delay of the injected water breakthrough, which delays the onset of scale formation in the producer; however, it can increase the amount of formation water (hence Ba2+ ions concentration), mainly from the low permeability zones, in the producer.
EOR techniques may have a major influence on the evolution of scaling ions in the produced water, which has to be taken into account for an optimum scale management strategy, to maximize oil production.
Graham, Alexander (Heriot-Watt University) | Salleh, Intan (Petronas) | Ibrahim, Jamal (Petronas) | Khairuddin, Khairunnisa (Petronas) | Singleton, Michael (Heriot-Watt University) | Sorbie, Kenneth (Heriot-Watt University)
The injection of sea water for the pressure support of oil fields is commonly associated with the biogeneration of hydrogen sulfide (H2S) by sulfate reducing bacteria and/or archaea (SRB/SRA). H2S is extremely toxic and corrosive, as well as providing a source of sulfide ions for the formation of iron, zinc and/or lead sulfide scale. However, H2S production is rarely, if ever, associated with seawater breakthrough and its retardation can be linked to a number of mechanisms.
Certain minerals (
Candidate mechanisms for sulfide scavenging by iron-bearing minerals have been experimentally identified and scavenging capacities have been determined for siderite FeCO3 in modified static adsorption tests and in dynamic pack floods, for aqueous-only systems. The effects of changing several conditions were studied, including temperature, initial pH and grain size.
A combination of dissolution/precipitation and surface displacement mechanisms were identified in the static bottle tests and further confirmed during the dynamic sand/siderite and crushed-core pack floods. ESEM-EDX and particle size analyses established the presence of mobile FeS (<100 µm) in the column after the flood had reached completion, confirming the bulk precipitation of FeS from dissolved Fe2+. Bringing together these two mechanisms allowed for the rationalisation of the observed scavenging profile, with reference to the Ksp of siderite. By further understanding the mechanisms of H2S scavenging experimentally, it will be possible to incorporate these into field-prediction models.
The absolute values obtained for the 8 wt% siderite packs were 1.03 and 1.74 mg/g at 25 and 96°C, respectively. Crushed core packs yielded significantly higher values of 5.76 and 5.80 mg/g at 25 and 96°C, respectively, which have been hypothetically attributed to the presence of iron-bearing clays in the core samples.
Azari, Vahid (Heriot-Watt University) | Vazquez, Oscar (Heriot-Watt University) | Mackay, Eric (Heriot-Watt University) | Sorbie, Ken (Heriot-Watt University) | Jordan, Myles (Champion X) | Sutherland, Louise (Champion X)
The application of chemical scale inhibitors (SI) in a squeeze treatment is one of the most commonly used techniques to prevent downhole scale formation. This paper presents a sensitivity analysis of the treatment design parameters, to assist with the automated optimization of squeeze treatments in single wells in an offshore field.
Two wells were studied with different constraints on total SI neat volume (VSI) and total injected volume (VT) including main pill and overflush volumes, followed by a field case squeeze optimization to demonstrate the sensitivity to lifetime and the cost function per treated volume of water. A purpose-designed squeeze software model was used to simulate the squeeze treatments and perform the sensitivity analysis. In the course of this optimization procedure, a "Pareto Front" is calculated which represents cases that
It was demonstrated at fixed values of VSI and VT (resulting in almost a fixed total cost for squeeze), the squeeze lifetime can be improved by increasing the scale inhibitor concentration in the main treatment slug; however, the increase in squeeze lifetime is greatly reduced at very high concentrations. Four generic scale inhibitors were used with different adsorption isotherms to validate these calculations. In cases where either VSI or VT is fixed, it is shown that the squeeze life does not monotonically increase by the other parameter and the cost function can be used to determine the optimum design.
Well squeeze optimization was performed and these recommendations were applied in the field. It was shown that a well-executed sensitivity study can prevent misleading results that miss the global optimum. A lesson learned was that the optimal designs entail injecting as much of the inhibitor as possible as early in the squeeze design as possible - provided formation damage effects are avoided. Also, our semi-analytical construction of the Pareto Front greatly helps to simplify and streamline the overall squeeze optimization process.
Al Kalbani, Munther (Heriot-Watt University) | Al Shabibi, Hatem (Heriot-Watt University) | Ishkov, Oleg (Heriot-Watt University) | Silva, Duarte (Heriot-Watt University) | Mackay, Eric (Heriot-Watt University) | Baraka-Lokmane, Salima (Total) | Pedenaud, Pierre (Total)
Injection of Low Sulphate Seawater (LSSW) instead of untreated Full Sulphate Seawater (FSSW) is widely used to mitigate barium sulphate (BaSO4) scaling risk at production wells. LSSW injection may no longer be required when the barium (Ba2+) concentrations in the produced water drop below a certain threshold. Such a trigger value could be estimated from the BaSO4 precipitation tendency. Relaxation of requirements for the Sulphate Reduction Plant (SRP) can significantly reduce operational costs. This study investigates the impact of several parameters on the timing and degree of relaxation of the output sulphate (SO42-) concentration by the SRP. Finally, the optimal switching strategy is proposed for a field case.
The strategy for switching from LSSW to FSSW, e.g. time and method (direct or gradual increase in the SO42- concentration) were initially investigated using generic 2D areal and vertical models. The sensitivity study included the impact of reservoir heterogeneity and initial Ba2+ and SO42- ion concentrations. Findings were later applied on a full field reservoir simulation model followed by a mineral scale prediction software to investigate the specific switching strategy for a field that has multiple wells and significantly more complex heterogeneity.
Results show that Ba2+ concentrations in the formation brine impact the choice of switching time more than the output SO42- concentration produced by the SRP. The degree of heterogeneity around the producers also has a significant impact on the switching time. Another parameter is the contrast in the permeability between layers; higher contrast allows longer period of co-production of the scaling ions and thus delays the switching time. In the field case, switching to FSSW at early times allows higher consumption of Ba2+ ions due to its
The study investigates the reservoir parameters that impact SO42- relaxation of LSSW injection for a field. Following the proposed workflow, the optimal relaxation strategy can be designed for other field cases.
With the current trend for application of Enhanced Oil Recovery (EOR) technologies, there has been much research into the possible upsets to production, from the nature of the produced fluids to changes in the scaling regime. One key question that is yet to be addressed is the influence of EOR chemicals, such as hydrolysed polyacrylamide (HPAM), on scale inhibitor (SI) squeeze lifetime. Squeeze lifetime is defined by the adsorption of the inhibitor onto the reservoir rock, hence any chemical that interacts with the adsorption process will have an impact on the squeeze lifetime. This paper experimentally demonstrates potential changes to inhibitor adsorption from a polymer EOR project by demonstrating the complex interactions between HPAM and phosphonate scale inhibitors with respect to adsorption.
This work presents a detailed coreflooding programme, supplemented with bottle tests, to identify the impact of HPAM on a diethylenetriamine penta(methylene phosphonic acid) (DETPMP) squeeze lifetime. A range of pH values, representing the expected inhibitor injection pH, have been studied on consolidated and crushed Bentheimer sandstone. A temperature of 70°C is used throughout as it represents the likely maximum temperature at which HPAM would be applied and the typical temperature at which DETPMP would be used in squeeze applications.
The results presented show that scale inhibitor application pH is key in defining the impact of HPAM on DETPMP adsorption. Neutral pH displays a reduced squeeze lifetime, believed to be due to reduction of adsorption sites by HPAM. However, this impact could be countered by injecting this type of scale inhibitor at a low pH (e.g. pH 2). Static tests performed alongside the corefloods show that even low inhibitor concentrations (as found in SI pre-flushes) are sufficiently acidic to fully precipitate the HPAM from solution, but did not impact the adsorption.
This study suggests, contrary to the commonly held view in the industry that EOR polymers may negatively impact squeeze lifetime, that with the correct selection of inhibitor type and their application pH it is possible to achieve the same results as in a conventional reservoir.
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.
Sour oil and gas production is commonly associated with sulfide scaling challenges originating from the produced aqueous phase. Iron sulfide (FeS) is one of the most common sulfide scales, and recent studies have shown promising dispersant chemicals are available to mitigate its deposition. In addition, successful applications have been reported in the literature, particularly from the North Sea. However, some of the limitations of these FeS chemical dispersants become evident under more severe (high H2S) sour conditions, such as those found in the Middle East, Russia and Canada.
The dispersant efficiency depends on the scale particle size, and larger particle sizes usually require higher dispersant dosages. Other factors that may influence the inhibitor dosage include reactant concentrations (cations and anions), pH, salinity and inhibition time. These factors were investigated using a newly developed anaerobic experimental setup that allows the careful addition and withdrawal of fluids from a closed anoxic system. Anaerobic vessels, such as vials and tubes, are deployed equipped with septa (thin membranes). Syringes were used to infiltrate the septum with minimal interference from sulfide retention while maintaining isolation from atmospheric oxygen.
Testing was performed over a sulfide concentration range from 100 to 1,000 mg/L. Higher levels of sulfide required higher loadings of scale inhibitor, essentially as a result of particle size increase. In addition, varying the salinity also had a significantly influence on the required dispersant concentration to maintain FeS suspension in solution. At lower pH condition, smaller FeS particles were produced and often inhibition was somewhat obscured by solubility effects. Also, suspending the FeS for longer periods of time required higher dispersant concentrations.
More severe sour conditions exceeding 1,000 mg/L of aqueous sulfide, have a detrimental effect on the both the efficiency and economics of the FeS inhibition treatments. In addition, the current high- performance dispersants cannot be squeezed into tight formations or shales, as their high molecular weight may cause severe formation damage. For such applications, alternative inhibition methodologies are required, and non-chemical inhibition may be considered.
How to estimate operational controls so as to optimize economic returns in CO2-WAG projects and reduce calcite scale risk? The reactivity and heterogeneity intrinsic to carbonate reservoirs make CO2-WAG (Water Alternating Gas) injection a big challenge. While miscibility effects greatly increase oil recovered, the presence of CO2 can cause severe flow assurance issues. The aim of this paper is to introduce a simulation-based methodology to optimize the design of CO2-EOR operations, considering economics, mineral scaling risk and environmental impact.
A compositional reservoir model was built to simulate a reactive 3-phase miscible flow in porous media. Aiming at maximizing the Net Present Value (NPV), we optimized the following operational variables: duration of waterflooding period; injection rates; producer bottomhole pressure (BHP); WAG ratio, gas half-cycle duration and number of cycles for different WAG stages (tapered WAG). We then used the forecasted data to quantify calcium carbonate scaling tendency for the scenarios of interest and design scale management strategies (squeeze treatments) with the lowest costs.
The optimal WAG design found through the methodology increased NPV by 55.6% compared to a base-case waterflooding scenario. We also found that performing a waterflood in a carbonate reservoir with high CO2 content will result in more severe calcite scale risk than applying equivalent WAG schemes. A lower production BHP can reduce the potential for precipitation, by allowing the CO2 to evolve from the aqueous solution within the reservoir, before it arrives at the production wellbore. On the other hand, a lower producer BHP can increase water production rates and, therefore, scale risk.
The proposed workflow provides valuable insights on the procedures involved in simulating and optimizing CO2-WAG projects with high calcite scale risk. Its application demonstrated the importance of an integrated analysis that seeks for higher economic returns in a sustainable manner, with reduced production issues caused by CO2 speciation.
Electromagnetic Devices (EMDs) have been used for scale management in the field. The proposed mechanism for their function is that the device imparts an electromagnetic pulse that provides sufficient energy to cause homogeneous nucleation, resulting in the formation of very small particles (5-8 microns) which pass through the production system, preventing heterogeneous nucleation and deposition. This paper summarises an experimental programme to examine the proposed mechanism of operation of the EMD under controlled laboratory conditions. Flow experiments were performed under ambient conditions using a mixed North Sea Seawater (NSSW) / Nelson Forties Formation Water (NFFW) scaling system. Experiments were performed with the EMD active and compared to baseline experiments where the EMD was inactive, to assess if the device impacted the scaling process.
A full quantitative assessment for each experiment was performed including; assessment of the mass of scale deposited and its location, full effluent analysis by Inductively Coupled Plasma Optical Emission Spectroscopy (ICP) and effluent sample filtration for solids content, morphology using Environmental Scanning Electron Microscopy / Energy Dispersive X-ray (ESEM/EDX) analysis and particle size distribution (PSD). From the experiments performed, it was found that the device impacted the scale deposition process in comparison to when it was not activated. Results indicated that although a similar amount of scale is lost from solution, less deposit was collected in the test apparatus itself. The precipitate in the effluent samples (which had passed through the apparatus) was found to have a mean particle size in the region of 10 microns, with a significant proportion of the distribution of particles below 1 micron; this was confirmed by ESEM/EDX and PSD. A further particle distribution range was identified as less than 0.22 microns. This material (10-20% of that injected) passed through the 0.22 micron filter used to collect the solid, but was accounted for when the experimental procedure was adapted.
The results from this study indicate that under the conditions used, the EMD has an impact on the scaling process resulting in homogeneous nucleation of smaller scale particles that are transported through the apparatus. This supports the mechanism reported previously and provides a greater understanding to how such devices work in the field.