SPE International Oilfield Scale Conference and Exhibition

The deposition of carbonate and sulphate scales is a major problem during oil and gas production. Managing scale with chemical application methods involving either scale prevention and/or removal are the preferred methods of maintaining well production. However, chemical scale control is not always an option, depending upon the nature of the reservoir and well completion and, in cases of severe scaling, the problem can render chemical treatments uneconomic unless other non-chemical methods are utilised.

A variety of non-chemical scale control methods exist, the most common being injection of low salinity brines or low sulphate seawater (LSSW) using reverse osmosis and a sulphate removal plant (SRP) respectively. In addition, careful mixing of lift gas, produced waters and reinjection, coatings, smart well completions with active inflow control devices (ICD) and sliding sleeves (SS) are other methods.

All of these techniques, including combinations thereof, are currently in use and the advantages and disadvantages of the key techniques are compared to chemical methods for both carbonate and sulphate scale control. A detailed example from a North Sea field demonstrates where downhole chemical scale control has not been required through a strategy of careful mixing of lift gas, brines and produced water re-injection. This was combined with understanding fluid flow paths in the reservoir and their likely breakthrough at production wells.

Consideration is given to the injection of smart brines to scale deep in the reservoir, and data from North Sea chalk fields shows how "in situ" geochemical reactions between the reservoir and the injected fluid can precipitate sulphate scales. The necessity to understand these geochemical reactions and their implications for improved oil recovery and the design of smart injection brines for scale control are discussed.

This paper presents a comprehensive review of non-chemical methods for downhole scale control and discusses how the use of these techniques can provide alternative scale management strategies through minimising or alleviating the need for downhole chemical treatments.

Scale inhibitors are commonly used for mitigating scale deposition risks in many oil and gas wells worldwide. Of the various chemistries used for scale inhibition, much research has gone into the various conditions in which each chemistry performs best (i.e. temperature, brine solubility, salinity, etc.)^4-6. Furthermore, it is known that dissolved iron (Fe²⁺ and Fe³⁺) can hinder the performance of scale inhibitors, some more than others³. Thus, applying this knowledge we can extrapolate which inhibitor chemistries might perform best under a given set of conditions. This knowledge can then be applied regionally where most production comes from the same or similar reservoirs and production conditions.

However, less research has been conducted on the effects of pre-existing iron sulfide deposits on the performance of scale inhibitors. Iron sulfide solids are becoming increasingly problematic in the oil field. The combination of iron sulfide with more conventional scaling deposits and the fact that scale inhibitors are surface active and tend to adsorb onto surfaces can yield very challenging situations. This paper discusses testing conducted on various scale inhibitor chemistries and evaluates how exposure to pre-existing FeS solids may impact performance. The various scale inhibitors were evaluated for inhibition performance against a set of controls (no FeS exposure) utilizing the NACE Standard TM0137-2007 "Laboratory Screening Tests to Determine the Ability of Scale Inhibitors to Prevent the Precipitation of Calcium Sulfate and Calcium Carbonate from Solution (for Oil and Gas Production Systems)" with an additional pre-test procedure to expose scale inhibitors in stock solution to a set weight of reagent grade ferrous sulfide (FeS).

Scale inhibitor chemistries evaluated include two polymers (scale inhibitor A and B) and five phosphorous based scale inhibitors (scale inhibitors C through F). The various configurations tested included: scale inhibitors alone, scale inhibitor plus FeS solids, scale inhibitor without FeS plus crude oil, scale inhibitor plus FeS and crude oil. The inclusion of the crude oil allowed an interface for potential micelle interactions. The results indicate scale inhibitors A, C and G were least affected by the presence of FeS with no regard to the presence of crude oil. With this study a scale inhibitor that worked best in the presence of FeS solids for the customer's field in the Permian Basin, where FeS has become an increasing issue, was recommended. This also allowed the customer to treat the FeS solids issue via the method that works best for them.

Halite precipitation from gas reservoir brines can cause significant decreases in hydrocarbon production or even complete blockage of the well. This has led to many gas wells either producing at diminished rates or being abandoned. Production decline related to halite scale is routinely treated with water washes either in a continuous system or with "mini squeezes" where water is batched in and held for few hours before production resumes usually with increased pressure. Introduction of halite inhibitors as part of the water wash or squeeze treatment has contributed to increased production by reducing the frequency and quantity of water used for treatment.

This paper summarizes the work performed to deliver to the industry a high-temperature, high-performance halite scale inhibitor. The product chemistry offers a true step-change in performance from existing technologies because of its high-temperature stability and halite inhibition efficiency at 420°F (bottom-hole temperature). An industry best-in-class rapid screening technique (kinetic turbidity test) was used to systematically evaluate all current technologies in the market place and to develop a detailed understanding on structure-performance relationships of functional groups. The resulting correlations led to synthesis of novel high-temperature stable chemistries with significantly superior inhibition on halite.

This paper also presents field cases of halite squeeze treatments from two different fields; an ultra hot (420°F) deep (17,460ft) dolomite gas well with severe halite deposition that required water washing every 48-72 hours and a shallow (6,000ft) hot (250°F) shale with erratic production where several water washes, work-overs and varied shut in periods did little to improve production. The ultra hot, deep well case history comes from a field in Texas where a detailed program of work was undertaken that led to squeezing in the halite inhibitor. Halite deposition had forced the operator to reduce production rates, with frequent workover to treat the well mainly with fresh water washes every 48 to 72 hours. After the introduction of the halite inhibitor, the gas well had been continuously producing for 40 days at the first instance and 60 days when the halite inhibitor dosage was increased. This is a marked improvement for the well and saves significant operating cost from well entries and deferred/lost production.

The paper describes a detailed methodology of halite inhibitor selection and the influence that temperature, pressure and salinity has upon application. Field application case histories share important lesson learned with regards to water washing volumes (small and large water washes) as well as the impact of extended shut in period on squeeze lifetime. These squeeze treatments provide valuable field insights to salt formation and prevention in gas wells and the use of the novel high-temperature inhibitor shows a new industry capability of inhibiting halite formation in hot gas well up to 450°F. This was proven by the successful field trials which showed an increase in the gas production at a higher draw-down rate without reducing the tubing/production pressure.

Formation of sulphate and carbonate scale is well understood within the hydrocarbon extraction industry with injection of incompatible water such as seawater into reservoir with significant concentration of barium, strontium and calcium. To overcome this challenge chemical inhibition has been utilized for many decades and in the past 15 years elimination/reduction of the sulphate ion source from injection seawater using sulphate reduction membranes has been employed.

This paper present laboratory work to qualify a scale inhibitor and field results of its application to prevent scale formation when an operator had to change from low sulphate seawater (LSSW) mixed with produced water (PW) for their water injection source to a blend of LSSW/PW and full sulphate seawater (SW). The increased level of sulphate presented a significant scale risk within the topside process on fluid mixing but more significantly increased the risk of scale formation within the near wellbore region of the injector wells which were under matrix injection rather than fracture flow regime. The qualification of a suitable inhibitor required assessment of the retention of a potentially suitable vinyl sulphonate co polymer scale inhibitors to ensure it had low adsorption and was able to propagate deep into the formation before being adsorbed from the supersaturated brine.

Coreflood studies using reservoir core were carried out to assess the scale risk of the LSSW/PW/SW brine, propagation and release characteristic of the short-listed scale inhibitors. The recommendation that followed the laboratory studies was to apply a batch treatment of concentrated scale inhibitor to each injector well to provide a high concentration pad of scale inhibitor that would be transported into the reservoir when the scaling LSSW/PW/SW fluid was injected. Protection was provided by continuous application of the same chemical at minimum inhibitor concentration to prevent scale formation within the topside and the desorption of the batched inhibitor within the near wellbore would prevent scale formation within this critical region. Thirteen injection wells were treated with a pad of 10% vinyl sulphonate co polymer scale inhibitor to a radial distance of 3 ft. prior to the start of LSSW/PW/SW injection. Highly scaling brine has been injected now for 16 months into the thirteen wells at an average rate of 25,000 BWPD per well with no decline in injector performance observed.

The lessons learned from this study are that changes in scaling potential within a PWRI system can be controlled by carrying out an assessment of location of scale formation and adoption of more typical production well scale squeezes treatment technology to protect the critical near wellbore region around PWRI injection wells.

It has been proven that scale squeezes can be conducted effectively in the unconventional, horizontal fractured wells in the shale reservoir of the Bakken when using an optimal scale squeeze chemistry. Previous work has discussed inhibitor selection and performance testing along with early case histories and modeling work. This paper discusses new case histories and Place-iT modeling results based on several procedural variations including a range of overflush volumes in the squeeze treatment procedure and the inclusion of acid cleanouts.

Novel, reduced-volume squeeze designs have successfully protected wells from scale deposition while limiting the direct and indirect costs associated with extra placement water. For unconventional shale wells in the Bakken, where produced water is typically very high in TDS and TSS, fresh water is most commonly used to execute squeezes. Reducing the total water volume reduces the costs of purchasing, transporting and storing fresh water. The amount of time and cost to pump the job is decreased. Less time and money is spent lifting the placement water, and consequently, there is less deferred production. In addition, in unconventional production acid treatments are commonly carried out in isolation to maintain production. In this work, applying acidizing stages at the front of the squeeze procedures, provides a novel "squimulation" process to fractured reservoir scale control treatments.

For these unconventional horizontal wells, the use of larger water volumes—either several times full wellbore volume and/or several times daily water production—has not been shown to improve the longevity or cost-effectiveness of squeeze jobs. Contrary to conventional well applications modeled with Darcy flow, it appears diffusion is the more applicable mechanism for scale inhibitor transport in fractured shale wells. This mechanism is consistent with a reduced dependence on water volume deployed in the treatments.

The lessons learned from the unconventional horizontal scale squeezes conducted in the Bakken have resulted in enhanced production and cost savings. There are significant implications for the industry as other key unconventional regions in the U.S. and around the world are looking into scale squeezes as an option for scale control.

Numerous saturation indices and computer algorithms have been developed to determine if, when, and where scale will form, but scale prediction can still be challenging since the predictions from different models often differ significantly at extreme conditions. Furthermore, there is a great need to accurately interpret the partitioning of H₂O, CO₂, and H₂S in different phases, and the speciations of CO₂ and H₂S. This presentation is to summarize current developments in the Equation of State and the Pitzer models to accurately model the partitioning of H₂O, CO₂, and H₂S in hydrocarbon/aqueous phases and the aqueous ion activities at ultra high temperature, pressure and mixed electrolytes conditions. The equations derived from the Pitzer ion-interaction theory have been parametrized by regression of over 10,000 experimental data from publications in the last 170+ years using a genetic algorithm on the super computer, DAVinCI. With this new model, the 95% confidence intervals of the estimation errors for solution density are within 4*10'⁴ g/cm³. The relative errors of CO₂ solubility prediction are within 0.75%. The estimation errors of the saturation index mean values for calcite, barite, gypsum, anhydrite, and celestite are within ± 0.1, and that for halite is within ± 0.01, most of which are within experimental uncertainties. This model accurately defines the pH of the production tubing at various temperature and pressure regimes and the risk of H₂S exposure and corrosion. The developed model is able to predict the density of soluble chloride and sulfate salt solutions within ±0.1% relative error. The ability to accurately predict the density of a given solution at temperature and pressure allows one to deduce when freshwater breakthrough will occur. Lastly, accurate predictions can only be reliable with accurate data input. The need to improve accuracy of scale prediction with quality data will also be discussed.

The presence of various levels of iron can be found in field brines primarily due to the mineralogy of the reservoir or from corrosion byproduct (Zhang 2015). The adverse effect of the presence of iron on the performance of scale inhibitors (SI) is known, and if left untreated, can lead to plugging of well tubing and pipelines. It can also cause fouling of separators; resulting in costly remediation and loss of production and revenues.

For the asset under study, traces of carbonate scale and iron sulfide were detected throughout a topsides production system. It was suspected the carbon steel production tubing was corroding over time and the byproduct was reacting with hydrogen sulfide from the souring reservoir. There are a number of well-developed methods that can be implemented to treat corrosion, bacteria, and dissolve the iron sulfide downhole; however, none of these application methods were available for this production system.

This paper will discuss the findings from laboratory testing for carbonate and sulfate scales in the precence of significant levels of iron. In order to select a proper scale inhibitor and the minimum effective concentration (MEC) for this system, a variety of chemistries were screened. Five scale inhibitors were selected for the testing, as shown in Table 1. The findings of the study show, Inhibitor D performed the best in the presence of iron at operationally viable dose rates in both static and dynamic testing conditions favorable for CaCO₃, FeCO₃, and BaSO₄ precipitation.

Table 1

Scale Inhibitor Chemistry

High Ca concentration up to 40,000 mg/L in produced water was observed in Marcellus shale gas wells, such extremely high concentration have great impact to solubility of sulfate scales. To evaluate this impact, the virial coefficients for Ca-SO₄ ion-interaction needs to be quantified in Pitzer equation for different P-T regimes. More solubility data with high Ca concentration at high temperature (>120°C) needs to be experimentally determined.

The solubility of anhydrite at Ca²⁺ concentration up to 1 m (mol/kg H₂O) from temperature of 120°C to 220°C and at saturated vapor pressure was measured. A stainless-steel pressure proof reactor was designed to contain a Pyrex bottle, in which reagent grade anhydrite powder was mixed with salt solution of 0.25 m, 0.5 m, 0.77 m, and 1 m CaCl₂. Sample was taken by using inner pressure to push solution through inline-filter, and then the Ca²⁺ and SO₄^2- concentrations in the filtrate was determined by inductively coupled plasma optical emission spectrometry (ICP-OES) and compared over time to confirm when solubility equilibrium was reached.

Results shows that current Pitzer's equation model (ScaleSoftPitzer 2017) predicts saturation index (SI) values with an error of less than 0.1SI at up to 0.77 m Ca²⁺, but shows an error as much as −0.21 SI at 1 m Ca²⁺ condition. For typical produced water with less than 30,000 mg/L Ca (about 0.75 m), the current model gives a reliable prediction of anhydrite solubility. If the produced water contains greater than 30,000 mg/L Ca, the model may yield error that are as much as −0.2 SI. Further experiments are needed to correct the Pitzer equation coefficients for better scale predication at higher than 30,000 mg/L Ca.

Iron sulfide deposition on downhole tubular is a ubiquitous phenomenon in sour gas wells, especially for these producing from high temperature and high pressure (HTHP) reservoirs. Many studies have been focused on iron sulfide formation and mitigation previously, the root-cause of iron sulfide deposition is still not well defined and the cost-effective scale management strategy is remained to be identified.

This paper presents some new progresses made for understanding the mechanisms of iron sulfide deposition in the sour gas wells, using a combined approach of laboratorial tests and model prediction.

Study results indicate that iron sulfide can deposit during both acidizing treatment and production stage. Large amount of iron sulfide could precipitate during acidizing treatment and potentially causes severe formation damage. During production stage iron sulfide is accumulated on tubular surface due to corrosion of the underlying metal.

This paper presents a fundamental study to understand the mechanisms of iron sulfide deposition in sour gas wells. Corrosion and scaling inhibition are recommended to mitigate iron sulfide deposition in sour gas wells, especially during acidizing treatment.

Produced water from the Bakken and Three Forks formations in the Williston Basin is notably high in total dissolved solids, which leads to many well maintenance issues related to halite scaling (salt precipitation). Fresh water is widely used to prevent halite scaling; however, initial treatment programs tend to "overtreat" the problem and leads to high operation and maintenance costs. An effort to improve halite scale management has been explored, which includes identification of wells that need fresh water injection; optimization of the fresh water volumes; minimizing deferred oil production; and preventing other scales associated with the presence of fresh water in the wellbore. Several methodologies have been applied to characterize halite scaling and achieve optimization of fresh water treatments. A scaling prediction model was developed and validated with literature data and field data. The model calculates saturation ratios and optimal fresh water volume, which provides critical inputs for treatment recommendations. Field tests have been conducted to dynamically characterize produced fluids. Results have influenced new methods for treatment and fresh water injection techniques. Halite scale inhibitors have also been examined in laboratory and field tests. This work resulted in optimizing both fresh water and chemical treatment programs to minimize halite scaling. Significant cost savings have been achieved from reduced fresh water usage, thereby lowered produced water disposal.