Bottle test and tube-blocking test are two major methods to estimate the minimum inhibitor concentration (MIC) for scale inhibitor applications, such as scale squeeze and continuous injection. However, they may not adequately represent the behaviors of scales and inhibitors in porous media. In this study, coreflood, bottle test and tube-blocking test were conducted, and the measured MIC values were compared to investigate the mechanism leading to the differences.

Bottle tests were conducted to determine the MIC of phosphino polycarboxylic acid (PPCA) by measuring the Ba²⁺ concentration in solution. Tube-blocking tests were carried out to determine the MIC of PPCA in stainless steel tubing by recording the increase of differential pressure. Finally, coreflood experiments were conducted to evaluate the performance of PPCA in porous media. Pressure changes were monitored along the core plug and were used to determine the location of BaSO4 deposition. Ba²⁺ concentrations in effluents were measured and compared with the bottle test results to investigate the performance of PPCA in porous media.

Results show that PPCA cannot stop scale deposition in porous media at the MIC determined by bottle tests and tube-blocking tests. Both bottle tests and tube blocking tests suggest an MIC of 6 ppm for PPCA. However, coreflood results show a noticeable increase of pressure in the first section of the core at 6 ppm. Moreover, the Ba²⁺ concentration in the effluent with 6 ppm PPCA of coreflood is just slightly higher that measured in the coreflood with no PPCA, which means that the MIC determined by bottle test and tube- blocking test cannot mitigate scale deposition in porous media. Sandpacks with higher permeability show higher permeability reduction after the same pore volume of water injection.

This study finds that the MICs determined by commonly used bottle tests and tube-blocking tests are not adequate to mitigate BaSO₄ deposition in porous media. The mechanism of BaSO₄ deposition and the behavior of inhibitors in porous media need to be further studied.

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.

Over the past 25 years the science of designing and optimising these treatments has advanced significantly with a better understanding of chemical/rock interaction, more effective modelling software to design the treatments and improved analysis methods for the determination of returning residual concentrations.

Scale squeeze treatments have in general been designed to treat between 6 to 12 months of water production before either the production layer or bulk produced water composition falls below minimum inhibitor concentration (MIC). In this paper examples of the process followed to design treatments for 24 months produced water for three offshore fields (North Sea, West Africa and Middle East) are outlined.

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.

This paper presents the field treatment designs from 4 case study fields, changing MIC values based on produced water composition which impacts chemical volumes required. The balance between cost of operation to deploy the chemical treatments to subsea vs platform wells are discussed. The implication of deferred oil associated with delayed production during pumping and post squeeze well clean-up was also considered in the design process for these wells. These case studies describe squeeze treatments which in certain wells treat over 25,000,000 bbls to MIC.

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.

Scale Inhibitor Squeeze treatments are some of the most common techniques to prevent oilfield mineral scale deposition in oil producers. A squeeze treatment design's effectiveness and lifespan is determined by the scale inhibitor (SI) retention, which can be described using a pseudo-isotherm adsorption, commonly derived from coreflooding experiments, although in some certain circumstances a new isotherm will need to be re-derived to match the field return concentration profile, once the treatment is deployed and samples are collected to measure SI return concentration. This new isotherm is used to design the next treatment. The objective of this manuscript is to quantify the uncertainty, which depends of the number of samples analyzed. In any inverse problem, there might not be a unique solution, which is in our context a pseudo-isotherm matching the return concentration profile. As a consequence, there will be a certain level of uncertainty predicting the next squeeze treatment lifetime. Solving this inverse problem in Bayesian formulation, incorporating the prior information, and the likelihood involving the return concentration profile, it is possible to quantify the posterior distribution, and therefore calculate the uncertainty range, commonly known as P90/P50/P10, based on the Randomized Maximum Likelihood (RML) approach. The P90/P50/P10 was calculated as a function of the number of samples available, differentiating from the early production and late production.

The results suggest that there is a correlation between the P90/P50/P10 interval and the number of samples, i.e. the differences between the P10 and P90 in terms of the forecast squeeze lifetime was wider the smaller number of samples. The methodology proposed may be used to determine the number of samples required to reduce the level of uncertainty predicting the lifetime of the next squeeze treatment. Although taking more samples may increase the cost per barrel for a treatment, the ability to predict accurately treatment lifetime will be more cost effective in the long term, as production might not be affected.

The use of reactive transport modeling (RTM) is increasing in the oil and gas industry for assessing the geochemical impact (e.g. scaling and souring) of various activities, such as waterflooding for improved oil recovery (IOR) and CO₂ storage. RTM is a technique that integrates fluid flow, transport of heat and solutes, and geochemical reactions. It can be used to model fluid compositional changes as well as rock mineralogical changes, caused by geochemical reactions, under flowing conditions. We use our in-house reservoir simulator (MoReS), coupled to geochemical software (PHREEQC), to carry out RTM. Simulations are based on the mixed solvent electrolyte (MSE) model from OLI Studio, a standard tool used by production chemists, enabling accurate computation of aqueous chemical reactions and partitioning of components between solid, fluid and gas phases.

Over the last few years we have used RTM to make scale predictions for several waterflooding projects around the globe. In this paper we will show results from these field cases and highlight the most important findings. In brief, these are:

Enabling mineral precipitation reactions in flow calculations improves the match between measured and simulated production water (PW) chemistry.

The developed workflow, based on learnings from various projects, is now used to forecast scaling risks in new projects and supports ongoing projects in mitigating risks (e.g. selection/timing scale squeezes).

In oil and gas industry, scaling prevention is one of the most important problems. While with more aggressive drilling and exploitation, scale control for the unconventional scale under complex water chemistry becomes more challenging. There are more chances to encountering with high temperature, high pressure, high TDS and some unconventional scale conditions. The modeling of the sulfide scale is notoriously difficult due to the extremely low solubility and complex water chemistry. Thus, the thermodynamic data is rare for sulfide minerals. Metal-sulfide-bisulfide complexes bring a large uncertainty for scale prediction. Another challenge is scale prediction in brine with high TDS, especially with high calcium concentration. Thermodynamic data with common ions Ca²⁺ and SO₄^2- is needed to improve thermodynamic models. The objective of this paper is to extend our knowledge for these exotic scale solubility predictions with both experimental studies and model validation. Some remaining questions in Pitzer theory framework have been thoroughly reviewed and discussed to improve the scale prediction for iron sulfide and high calcium condition. The newly derived models are able to predict the saturation index (SI) within ±0.3 unit for iron sulfide and ±0.15 units for common sulfate scales, respectively. These developed models have been incorporated into ScaleSoftPitzer for practical use in the oil and gas production.

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 (SO₄^2-) 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 SO₄^2- concentration) were initially investigated using generic 2D areal and vertical models. The sensitivity study included the impact of reservoir heterogeneity and initial Ba²⁺ and SO₄^2- 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 SO₄^2- 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 in situ precipitation. Ba²⁺ is no longer a limiting ion, and so a higher degree of deep reservoir precipitation reduces the requirement for prolonged LSSW injection. Another strategy is a gradual relaxation of LSSW output, which allows even earlier build-up of the injected SO₄^2- concentration compared to the direct FSSW switch.

The study investigates the reservoir parameters that impact SO₄^2- 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.

Mineral scaling issues have been reported in many alkaline and Alkaline-Surfactant-Polymer (ASP) projects. The role of the in situ mineral reactions on the produced scaling ions and pH has been little reported in the literature. The objective of this study is to investigate the impact of the in situ chemical and geochemical interactions on the scale precipitation risk when the fluids reach the wellbore, and their inhibition during Alkaline-Surfactant (AS) and ASP flooding processes.

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 in situ rock dissolution, mineral precipitation and brine mixing reduce the produced ion concentrations (Ca²⁺, Mg²⁺, HCO₃^-) and pH compared to the initial concentration and the injected pH value. The calcite scaling risk can be high during Na₂CO₃ injection while silica and Mg(OH)₂ scales are potential minerals that will precipitate in the production system during NaOH injection. Uncertainty in the mineral reaction rate parameters, especially mineral surface area, is important and must be captured, as this may impact the scaling risk in the producer. Among the studied flooding options, ASP with pre and post polymer slugs shortens the calcite scaling period, reduces the scaling ion concentrations and the produced water rates. This case, then, requires the least number of squeeze treatments, the lowest scale inhibitor volume, and delivers the highest incremental oil recovery.

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.

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 (V_SI) and total injected volume (V_T) 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 cannot in principle be improved upon. An analysis of these results also shows that this Pareto Front can be generated by a semi-analytical method, as shown for the first time in this paper.

It was demonstrated at fixed values of V_SI and V_T (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 V_SI or V_T 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.

A ceramic proppant based chemical delivery system is known to be able to deliver multiyear inhibition of scale with a onetime treatment. The delivery system can be used to replace part of the proppant in frac and frac packs completions, be used as the gravel in gravel packs, or simply as a transport mechanism to place production chemicals in an acid-frac stimulated reservoir.

This chemical delivery system has been recently applied offshore Congo for the first time. Learnings from the implementation of this technology both onshore and offshore in the United States have enabled the product usage to expand internationally. The use of this delivery system has eased the operational challenges seen in offset wells caused by repeated treatment of scale inhibitor. Increased space has been freed on the platform and all interventions for scale control have been eliminated.

Results presented in this paper will include the design of this work for the application in Congo, including infusion and release of the inhibitor from the ceramic carrier and design of the control membrane to achieve the desired protection time. This design work also includes the learnings from multiple other applications that were combined for this new area of implementation, including case histories from other basins.

This paper will be beneficial for production engineers who desire a cost effective solution to deploy production assurance chemicals in a one-time treatment, regardless of well type, resulting in a multi-year solution.