SPE International Oilfield Scale Conference and Exhibition

A new laboratory test method for qualification of scale inhibitors for carbonate, sulphate and sulphide scale has been demonstrated. The new method reflected conditions at the first stage separator at Gullfaks A in a more realistic way than by use of the more common dynamic tube blocking test. Results of this method have been compared with dynamic tube blocking and static scale inhibition tests and a full-scale field test.

The method developed includes iron particles, realistic H₂S and CO₂ pressures under anaerobic conditions allowing water chemistry similar to field conditions. The method can be utilised for water with carbonate or sulphate scale potential or a mix. A pH closer to system conditions and scaling on surfaces can be achieved without adjustment of the water composition. The residence time can be up to 5 minutes, which typically represent the residence time in for example separators. The results are interpreted through visual observations through glass coils and Scanning Electron Microscopy with Energy Dispersive Spectroscopy (SEM/EDS) analyses of steel coils.

Using the new method, significant scale was formed when the incumbent scale inhibitor was tested which was also observed in the field. Several alternative scale inhibitor chemistries were recommended for evaluation based on environmental properties, field experience and cost efficiency. When testing the chemistries with the new method only one inhibitor gave acceptable results (no scaling nor co-precipitation of scale and scale inhibitor). This inhibitor was recommended for further testing in a two-week field test. The field test included quantification of suspended solids and a filter rig test. The results from the field test confirmed the laboratory results showing that the selected inhibitor was more efficient than the incumbent.

Understanding the reservoir connectivity advances engineering and management decisions and enhances overall field performance. A method to investigate injector to producer connectivity from an identified proportion of the injected brine in the produced water is proposed.

Chloride, sodium, boron and lithium are ideal tracers: typically they do not participate in geochemical reactions. These ions track injection water without retardation, and if their concentration differences with formation brine are high enough to overcome measurement errors, then they may be used as indicators of the mixing ratio between injection and formation brines. This paper proposes the use of this mixing ratio to distinguish brines and to calculate the normalised contribution of injected water in the cumulative produced water volume. A producer to injector connectivity plot allows engineers to categorise the pressure support for production wells in one plot.

This approach was applied to North Sea field data. A mineral scaling risk analysis was performed using the Injector Contribution characteristic plot. Wells being supported by commingled injected seawater and aquifer water were most at risk of BaSO₄ precipitation. Historic data for a field case were analysed to examine potential scaling regimes. A set of well candidates for enhanced oil recovery to reduce residual oil in the oil leg was also identified. Most of the water produced in these wells came from injectors, rather than from the aquifer. Those wells have good communication throughout the oil leg and as a result quick water breakthrough occurs. As well as resulting in an early onset of BaSO₄ scaling, an Enhanced Oil Recovery (EOR) chemical that is injected would more quickly reach the producers and therefore the potential for chemical EOR applications can be measured. This suggested metric helps to identify that other wells do not experience much seawater production, but are more strongly supported by the aquifer, and so there would be no apparent benefit in reducing residual oil by injecting chemical. This set of wells might benefit potentially from infill drilling nearby, or conformance control methods.

The proposed technique does not require additional sampling to be performed over and above the measured historical produced water compositions that are routinely collected by operators during offshore production for scale management purposes. The analysis to select well candidates for EOR or areas for infill drilling is significantly more challenging using a conventional approach, and we propose that this novel metric of "Producer to Injector connectivity" will be beneficial for the decision making process.

Scale deposition in oilfield production systems is influenced by thermodynamic supersaturation and kinetics, but also by hydrodynamic effects such as surface shear stress and turbulence. Results from experimental work investigating the impact of these hydrodynamic factors on scale location and correlating them to field flow regimes are presented.

Laboratory tests have been conducted using both a benchtop jet impingement method and large-scale, high flow rate "pilot rig" apparatus. Both of these systems result in high shear stress conditions and can simulate hydrodynamic regimes representative of those expected in devices such as inflow control valves, inflow control devices, and sand control screens. The pilot rig is able to reproduce field-representative flow rates and fluid flow dynamics through full-size test pieces containing nozzles and restrictions.

The results of this work demonstrate that the hydrodynamic regime has a significant influence on scale deposition. Increased levels of surface shear stress and turbulence result in a greater potential for scale formation than low shear, laminar flow conditions. This is particularly apparent in systems which are mildly supersaturated. The location of scale deposits was found to correlate with local shear stress and the pilot rig tests confirmed field observations that zones experiencing the highest level of shear are not necessarily those with the greatest deposit; the induced scale may deposit downstream in areas of lower surface shear. Additionally, the presence of these high shear locations upstream of the lower shear regime may lead to scaling in the lower shear region which would otherwise not be experienced. Supportive Computational Fluid Dynamic modelling of fluid flow within the pilot rig system correlated with the experimental findings is also described.

This work allows a greater understanding of the hydrodynamic factors, in particular surface shear stress, influence oilfield scale deposition and has demonstrated the utility of both benchtop and pilot-scale methods for testing under appropriate conditions.

Scale inhibitor squeeze treatments are used to prevent scale deposition in production wells. A treatment consists of injecting a scale inhibitor slug at a concentration between 5 and 15%, referred to as the main treatment, followed by an overflush, which will push the chemical slug deeper into the reservoir. During injection, the stages might undergo some degree of mixing in the tubing. This paper addresses the impact such mixing would have on the squeeze lifetime. A consequence of mixing between main treatment and overflush stages in the well tubing would be that although the same overall mass of scale inhibitor was injected, it would be distributed over a larger volume of water and therefore be exposed to the rock formation at a lower concentration than planned in the design. The degree of mixing in the tubing depends on a number of factors, such as tubing length and diameter, and the pumping rate. The phenomenon is described by the longitudinal dispersion coefficient, which may be calculated.

The resulting calculation may be defined as the spreading of a solute along the longitudinal axis, which leads to the spread of an initial high concentration slug with a low spatial variance to a final stage of low concentration with high spatial variance. The main objective of the paper is to study the effect of the degree of mixing of the main and overflush stages on the squeeze treatment lifetime. The net effect of full mixing would be that instead of there being two different stages at very different scale inhibitor concentration, a single stage at a lower concentration might be exposed to the rock formation. Two mixing profiles were considered, a short and long tubing; where the total injected volume is greater than and less than the total tubing volume, respectively. A number of levels of mixing were considered and compared to the base case, where no mixing was allowed. The results showed that squeeze lifetime is not significantly reduced if mixing occurs in a short tubing interval, whereas it can be reduced by up to 20% in a longer tubing interval.

The paper reviews operational issues that arise when MEG is used for hydrate inhibition, especially when it is regenerated and recirculated. Thermodynamic equilibrium software can assess the scaling risk to some extent. Utilisation of data on nucleation and growth of scale formers like calcium carbonate can enhance the accuracy of the predictions.

The presence of MEG and the conditions encountered in MEG systems favour aragonite crystallisation when the MEG solutions become supersaturated in CaCO₃. MEG retards the growth rate of all three CaCO₃ polymorphs, but the reduction is smaller for aragonite than for calcite and vaterite. The growth rate of siderite is also slowed down by MEG. However, MEG does not inhibit the nucleation and growth of carbonates.

Alkalinity in recycled MEG will enhance the scaling risk downstream of the MEG injection point when there is calcium in the produced water. Scale can be mitigated by scale inhibitors, but the selection process must ensure that the chemicals are tested at relevant conditions; i.e. with the expected MEG concentration, alkalinity and pH.

Many MEG recovery units have a pre-treatment system for controlled removal of carbonates and to some extent hydroxides. This reduces the amount of scale that may form in the regeneration system. In the pre-treatment, alkalinity dosed as hydroxide and/or carbonate forces precipitation of calcium, strontium and iron carbonates and magnesium hydroxide. The supersaturation is generally so high that scale inhibitors are not able to prevent precipitation of the solids.

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.

A key part of the oilfield scale management toolbox is the ability to determine the concentration of residual scale inhibitors and scaling ions in produced waters. This data is essential to providing correct recommendations for how to manage and inhibit scale in a particular system, as well as monitoring the efficacy of scale management processes already in place.

The progression of analytical techniques over the last two decades has provided enhanced methods for accurate detection of ions and scale inhibitors to low limits of detection, however, correct detection of analytes present in a sample in the laboratory does not necessarily equal characterisation of the analytes in-system as they were present at the point of sampling.

The collation of a range of preservation techniques, each appropriate to a different group of analytes, forms the basis of this paper. The results of several field applications of incorrect sample preservation are outlined and the alternative preservation technique used to correct the analysis will be detailed.

The implication of using the correct preservation technique will be clearly shown to have an impact on scale management where it would lead to reduction of over treatment, leading to increased revenue, whilst also eliminating incorrectly scheduled early well interventions.

Produced water can be routely re-injected into reservoir for purposes including pressure support and environmentally acceptable disposal. Scale prevention and control is required to maintain well injectivity and longetivity. This paper presents a comprehensive scale study to reliably access injection well scaling potential and establish fit-for-purpose/optimal scale management strategy. Field water samples were appropriately collected and characterized. Laboratory testing was well designed/conducted to understand scale formation potential, and determine required scale inhibitor dosage. Study results suggest calcite and silicate scales can be of potential concern, and increase of downhole temperature or/and fluid residence time (e.g., under abnormal operation condition with low injection rate or well shut in) at near wellbore formation can lead to higher scaling risk. Testing results show that one scale inhibitor product (originally recommended by chemical vendor) at high dosage can potentially accelerate scale formation leading to more solid precipitation. Alternative inhibitor products were tested and scale inhibitor selection and treatment strategy was optimized based on testing results.

Increasing production activities in sour environments with equipment and piping made of low corrosion- resistant carbon steel result in significant iron sulfides (FeS) corrosion and scaling problems. FeS scale control is challenging as FeS formation is favored in production water chemistry (extremely low solubility and fast precipitation kinetics) with complex phase transformations. Efficient chemical control of FeS scales has not been found. A polymeric compound containing amide or its derivative functionalities showed a promising effect by controlling the FeS particle size on a nano-meter scale at threshold quantities. The FeS scales were successfully managed by forming a stable FeS particle suspension in the aqueous phase without partitioning into the oil-water interface. Current development focuses on understanding the interactions between the polymeric-compound based dispersants and environmental factors such as the presence of an oil phase, as well as silica. In addition, performance improvement of the identified dispersants by new chemical additives has been explored. Our results show that biocides such as Tetrakis (hydroxymethyl) phosphonium chloride (THPS) may not be as effective as needed for FeS scale inhibition benefit. At the tested conditions, EDTA shows satisfactory FeS scale inhibition and dissolution performance. In addition, silica significantly affects wettability of FeS particles with part of the previously oil-wet FeS partitioning into the aqueous phase. The FeS inhibition and dissolution effects of EDTA are kinetically "poisoned" by silica; while FeS-dispersing effect of polymeric compounds remains unaffected. However, the previously-shown ability that polymer dispersants keep already-formed large size FeS particles in the aqueous phase is also impaired.

Deposition of inorganic scale on downhole completion equipment contributes to significant downtime and loss of production within the oil and gas industry. High temperature/high pressure (HT/HP) fields have reported build-up of lead sulfide (PbS) scale as a consequence of reservoir souring. This paper reports on the design of an experimental rig allowing diffusion of H₂S into a scaling brine under dynamic environments. Multiphase conditions induced by introduction of a light distillate within the system were used to create an emulsion in order to reflect more accurately the scaling process occurring within sour systems. The results showed that the presence of an oil phase within the system caused the lead sulfide nano crystals to reside at the oil- water (o/w) interface; increasing surface build-up propensity through an adhesion process. Performance of a range of coatings for potential application in oilfield environments was determined through gravimetric measurements and microscopy techniques and the wettability of surfaces was shown to have a significant influence on the degree of lead sulfide deposition in a multiphase system.