Carbon Capture and Sequestration (CCS) is a geologic and engineering enterprise designed to reduce atmospheric emissions of greenhouse gases (GHGs). Extensive research links the GHG concentration in the atmosphere to the observed change in global temperature patterns (IPCC, 2013; Cox et al., 2000; Parmesean and Yohe, 2003). CCS technology could play an important role in efforts to limit the global average temperature rise to below 2°C, by removing carbon dioxide originating from fossil fuel use in power generation and industrial plants.

Briefly stated, carbon capture and sequestration (CCS) will help us to sustain many of the benefits of using hydrocarbons to generate energy as we move into a carbon-constrained world. Even though the CO2 generated by burning hydrocarbons cannot always be captured easily in some cases (as in oil used for transportation), sequestration of CO2 from other sources (such as coal-fired power stations) can help to create, to some degree, the “headroom” needed for the volumes of CO2 that escape capture. Because of the likely continuing competitive (direct) cost of hydrocarbons and in light of the huge investment in infrastructure already made to deliver them, the combination of fossil fuel use with CCS is likely to be emphasized as a strong complement to strategies involving alternative, nonhydrocarbon sources of energy. Moreover, the exploitation of heavy oil, tar sands, oil shales, and liquids derived from coal for transportation fuel is likely to increase, even though these come with a significantly heavier burden of CO2 than that associated with conventional oil and gas. CCS has the potential to mitigate some of this extra CO2 burden. If we wish to sustain the use of oil, gas, and coal to meet energy demands in a carbon-constrained world and to provide time to move toward alternative energy sources, then it will be necessary to plan for and implement CCS over the coming decades. Subsequently, we should expect a continued need for CCS beyond the end of the century.

Produced water is an inextricable part of the hydrocarbon recovery processes, yet it is by far the largest volume waste stream associated with hydrocarbon recovery. Water production estimates are in the order of 250 million B/D in 2007, for a water-to-oil ratio around 3:1, and are expected to increase to more than 300 million B/D between 2010 and 2012 (Figure 1, Dal Ferro and Smith 2007). Increasingly stringent environmental regulations require extensive treatment of produced water from oil and gas productions before discharge; hence the treatment and disposal of such volumes costs the industry annually more than USD 40 billion. Consequently, for oil and gas production wells located in water-scarce regions, limited freshwater resources in conjunction with the high treatment cost for produced water discharge makes beneficial reuse of produced water an attractive opportunity. Figure 1 - Global onshore and offshore water production (Dal Ferro and Smith 2007).

This paper presents a case history of scale treatments performed in a well producing in the North Sea. Kvitebjørn is a gas and condensate producer with high reservoir pressure (480bar) and high temperature (152°C). Well A-7 T2 started production in January 2014 and has a history of a carbonate scale precipitation.A few months after start-up, formation water breakthrough was observed in addition to a reduction in Production Index.

Due to challenges with removing scale by wireline, interventions using scale dissolver were performed in late 2017 and early 2018. The second dissolver treatment was followed by a scale squeeze to protect the well from further scaling. The chemicals used were qualified according to the Operator’s technical specifications. Due to high reservoir temperature, thermal stability was vital in the qualification process. The formation permeability was moderate, which was important to consider when evaluating the risk of formation damage.

The environmental category for the chemicals versus their performance was an important factor in the qualification process. Modelling programs were used to assess placement distribution under various bullhead pumping conditions. For the scale squeeze, a modelling program was used to simulate treatment lifetime using isotherms derived from laboratory core flood testing.

Water samples were taken from the well and analysed onshore in the supplier’s laboratory. Following the scale squeeze, water samples were taken from the well during the entire treatment lifetime. Ion concentrations and residual inhibitor concentrations were monitored together with production parameters to assess the scale situation in the well.

Following the treatments, the well showed an increased gas production. The well produced 1.2MSm³ at 40% choke before the treatments and 1.2MSm³ at 6-7% choke after. Laboratory work combined with field experience from this first well that was treated, forms the basis for possible future treatments. Being able to treat wells through pro-active and efficient scale inhibitor squeeze treatments will allow for continued production of wells exposed to scale risk, avoiding the cost and risks associated with mechanical scale removal and avoiding production deferral associated with potential dissolver jobs.

Scale control and inhibition is very important for maintaining flow assurance of oil production. Several specialty chemicals are used to delay, reduce or prevent scale deposition and, in particular, polymers and phosphonate-based chemicals have been used extensively. The accurate and precise topside measurement of scale inhibitors plays an important role in assessing the efficiency of scale squeeze and continuous-chemical injection treatments. At present, numerous techniques exist for scale inhibitor (SI) analysis but each method has its own limitation and often these methods give results of either total chemical content or elemental analysis without details of chemical speciation. Furthermore, most techniques often lack the ability for on-site analysis on fresh produced water samples, which yields the potential for quick and more accurate and precise information due to minimal sample degradation.Nanotechnology-based Surface Enhanced Raman Spectroscopy (SERS) developed as the next-generation method to fill the gap in speciation of phosphonates and to determine low concentrations of different scale inhibitor chemicals in produced brines in a timely and cost-effective manner.Particular focus is placed upon the individual and mixed analysis of a novel phosphonate and Deta Phosphonate (DETPMP) respectively. Development of this method with handheld instrumentation provides better detection and quantification of scale inhibitors in the field and reduces time and cost compared to sending samples to off-site laboratories for data collection.

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. 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. The implication of deferred oil associated with delayed production during pumping and post squeeze well cleanup was also considered in the design process for these wells. 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. 2 SPE-200701-MS

Calcium Sulfate (CaSO₄) is precipitated due to super saturation of Ca²⁺ and SO₄^2-ions that can be created due to change pH, pressure, temperature or due to mixing of the brines. Among the CaSO₄ species, CaSO₄.2H₂O or gypsum is stable in solid phase at lower temperature below 50 °C which has been observed frequently in wells treated with CO₂ flooded-EOR technique. As a result, mineral scaling, especially calcium sulfate (gypsum) deposition has been a serious flow assurance problem in oil and gas production leading to production shut down because of formation damage or equipment failure. Use of scale inhibitors may be the efficient method to prevent the scale formation. However, there is a knowledge gap on types of scale inhibitor that might be efficient in controlling the calcium sulfate scaling under varied field conditions. Additionally, there is a need of an efficient method to evaluate the performance of scale inhibitor and simulate the dynamic field condition.

This study provides information on several options of inhibitors to control CaSO₄ at various conditions as established with modified laser-light based Kinetic Turbidity Test (mKTT) method that can assess several samples over a range of concentrations simultaneously. Other newly developed modified Continuous Stirred Tank Reactor (mCSTR) method showed to be an efficient tool to understand scale inhibitor performances, as it can overcome limitations of dynamic scale loop (DSL) with low residence time and low volume capacity of capillary tubing. Similarly, as minimum effective dosage (MED) needed can be easily established in one setting with mCSTR method. It showed much better efficiency compared to that of standard bottle test, which suffers lack of dynamics and multiple bottle tests needed to establish MED. This study provides more effective test methodologies for scale inhibitors performance testing. The mCSTR apparatus can be used for various mineral scales such as barium sulfate, halite, calcite, etc. Additionally, this study will provide a mathematical model (scaling risk-inhibitor dosage recommendation) via mCSTR method which can be used to predict scaling tendency and inhibitor need under desired conditions.

Scale formation in oil and gas wells commonly occurs, causing not only pipeline blockage, equipment failure, or formation damage during production, trasnsportation, and treatment, but also premature abandonment of wells in serious cases. Although types of mineral scale occurrence depend on the types of ions in water, sulfate and carbonate scales are the most commonly found scales in oil and gas fields. In this study, we investigated a single approach to prevent complex mineral scales from deposition using water-soluble polymer dispersant or the combination of water-soluble polymer dispersant of carboxymethyl cellulose (CMC) and phosphonate inhibitors of diethylene triamine penta(methylene phosphonic) acid (DTPMP) or hexamethylene diaminetetra (methylene phosphonic) acid (HDTMP) in highly saturated solution or high ionic strength (IS) brines. This study shows that CMC effectively prevents sulfate (barite and gypsum) and carbonate (calcite nd iron carbonate) scales from deposition. The particle size dispersed in the presence of CMC remains in nanosize ranges. When CMC was combined with phosphonate inhibitors of DTPMP or HDTMP, sulfate scales were even more effectively controlled, compare to CMC or phosphonate inhibitors by themselves. In the combination of CMC and DTPMP, the majority of barite (> 90%) remained in a size of smaller than 200 nm and the total mass of barite deposition on 316 stainless steel coupon was negligible, as low as 0.079% of total input mass. Gypsum formation was inhibited for at least 6 hours and gypsum particles remained in a size of smaller than 200 nm for 12 hours in the combination of CMC and HDTPM. For calcite, measured induction time was 134 minutes and calcite particles were dispersed for at least 15 hours with its average particle size of 396 nm in the presence of CMC. Iron carbonate particles were well dispersed for 2 hours in the presence of CMC.

An oilfield operator relies extensively on heat exchangers (Hexs) to break heavy oil emulsions. A workhorse inhibitor worked reliably to control thermally induced scale precipitation caused by local hard waters. However, an upsurge of scale-related Hexs tubing blockage occurred during a harsh winter that coincided with a breakthrough of enhanced oil recovery (EOR) polymer into some water sources. Through comprehensive lab testing, root causes of the failure were identified. A new product was developed featuring superior tolerance to variable production parameters, especially Hexs temperatures.

Scale inhibitor efficacy is strongly influenced by overall scaling conditions including water chemistry, temperature, pressure, and presence of incompatible chemicals. In this study, scale precipitates collected from Hexs were characterized using environmental scanning electron microscopy techniques. New inhibitor chemistries were screened through thermal aging; then evaluated for inhibition performance by dynamic tube blocking methods at temperatures ranging from 42°C to 171°C. An additional performance test was designed for the final candidate to further investigate adverse impacts from the EOR polymer and incumbent scale product if a dual-product treatment is required throughout the field fluid system.

The incumbent effectively inhibited scale formation at ≤120°C but showed reduced performance at 160°C. This result is consistent with field records indicating most tubing blockages occurred during the coldest days when Hexs temperature was raised to 160°C to increase heat to treat fluids. Meanwhile, it also suffered antagonistic effects from the EOR polymer. A dozen new inhibitor chemistries were studied including polymers and phosphonates. Polymeric inhibitors had higher thermal aging ratings but were less compatible with the waters involved. Ideal candidates must have thermal stability, high-temperature inhibition performance, and applicability to wide ranges of operational conditions, including Hexs temperature, water hardness, bicarbonate, and foreign substances. Thus, a single product can be applied to the entire field and simple dosage adjustments can readily handle most expected scaling risks. The new product passed all the criteria and significantly reduced operating and equipment replacement cost since deployment.

This paper provides a unique scaling challenge that combined ultra-high temperature and EOR polymer influence, and a systematic approach to understanding and resolving the issue.

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 (Verri et al., 2017). The authors show how this previous procedure is intrinsically general, but requires modifications depending on specific field variables such as oil type, topside vs reservoir data availability or the use of integrated or separate PVT and scale prediction software.

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 Appendix 1 where the "correct" answer is known, and the workflow is demonstrated to be rigorous in that it recovers this correct answer. This data can be used to test any other procedures for rigorously predicting carbonate and sulfide scales from field data.