Paper No. 5480 - slb.com/media/Files/technical_papers/500/5480-NACE.… · NACE International, Publications Division, 15835 Park Ten Place, Houston, Texas 77084. ... laboratory testing

Scale Deposition Control and Management in Subsea Fields

Hua Guan

OneSubsea Aberdeen AB32 6FG

United Kingdom

ABSTRACT There is general industry recognition that production chemistry is a growing concern from the conceptual design and FEED stage through to the lifetime operations. The global opportunities within the subsea market, in both greenfield and brownfield, have only become more complex. The increasing complexity in subsea fields has brought significant challenges in terms of scale control and management; highlighted by the uncertainties of scale risk evaluation. Due to the lack of reliable water compositions (e.g. commingled water), inhibition chemicals are more vulnerable for degradation under harsh subsea environments, and well access / interventions become difficult and costly. The main challenges facing continuous scale inhibitor applications are associated with the limited chemical injection line, long tieback with large pressure/temperature (P/T) variation, and long residence time; while well access and downhole placement can be particularly challenging for squeeze application. The inadequate water data, the potential ion stripping, and the limitation of currently used thermodynamic scale prediction software all contribute to the uncertainty and inaccuracy in scale evaluation. This paper will provide an overview of the scale management challenges associated with subsea fields while focusing on the development over the years in terms of laboratory evaluation techniques, analytical advancement, hardware developments, and modeling integration practices. Keywords: scale management, subsea fields, scale prediction tools, hardware, subsea sampling

INTRODUCTION

Inorganic scale deposition is a common flow assurance problem throughout a field’s lifetime, as long as there is water production from the field (1-2). Scale can deposit at any location that is in contact with water, such as in the reservoir, the near-wellbore and wellbore, production tubular, wellhead, flowlines, downhole, and topside production and processing facilities (e.g. pumps, separator, heat exchanger).

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Paper No.

5480

©2015 by NACE International. Requests for permission to publish this manuscript in any form, in part or in whole, must be in writing to NACE International, Publications Division, 15835 Park Ten Place, Houston, Texas 77084. The material presented and the views expressed in this paper are solely those of the author(s) and are not necessarily endorsed by the Association.

Negative consequences on hydrocarbon production, such as production decline, flow restriction, and complete blockage, are often experienced by the field if not properly controlled. Conventionally, scale is controlled by the use of chemical inhibitors, either by squeeze treatment into the reservoir or by continuous injection into the well. However, with the increasing complexity of subsea fields, the efficiency of such conventional scale control and management plans is often compromised due to a number of uncertainties in risk evaluation, chemical stability, well access, reliability of chemical injection system, performance monitoring, and analysis. Over the last 15 years, there has been a dramatic increase in the number of FPSO/FDPSO vessels and subsea completions worldwide. Production from these subsea fields is associated with unmanned platforms, wet trees, long tiebacks with large P/T variations, and limited chemical injection lines, while the completion strategies often involve long, horizontal, complicated well shapes, multi-lateral with Inflow Control Devices (ICDs), and complicated sand control technologies. All of these have brought significant challenges in terms of scale control and management; highlighted by the uncertainties of scale risk evaluation. Due to the lack of reliable water compositions (e.g. commingled water), inhibition chemicals are more vulnerable for degradation under harsh subsea environments, and well access/interventions become difficult and costly. These have become the main drivers in the development of laboratory technologies, analytical toolboxes, computer modeling tools, and subsea hardware systems that enable effective scale control and management in subsea operation fields.

LABORATORY EVALUATION

With exploration and operations driven to ever greater depths for offshore oil and gas, there are increasing challenges associated with subsea and deepwater production that demand new and innovative techniques. This has necessitated the development of chemical products to meet stability, compatibility, and performance levels encountered in subsea fields. Although similar to the challenges faced by other production chemicals, the particular challenges associated with scale control in subsea fields involve larger temperature fluctuations from seabed temperature to HTHP conditions, higher shear rates, greater pumping pressures, longer residence times, and limited injection lines. Due to the extended length and small diameter of these injection lines, the associated back pressure and shear rates placed upon the production chemicals are much greater, requiring limitations in product viscosities. The extended reach of umbilicals leads to longer residence times. Extended lab tests are required to evaluate the scale inhibitors suitable for such harsh environments. These tests will ensure that the chemicals used in these environments do not cause umbilical blockage and maintain inhibition performance during the whole period of production. The challenges and inhibition mechanisms under HTHP conditions (3-5) and for cold seabed conditions (6-7) have been reviewed in a number of publications. Production chemicals applied in deepwater systems undergo a wide range of laboratory testing before deployment (8-9) . These tests replicate the typical conditions experienced in deepwater chemical injection systems. The suite of tests include (but are not limited to) extended stability and compatibility, high-pressure rheology and performance, hydrate protection, and environmental impact. Numerous scale-control chemicals have been successfully evaluated and deployed into traditional offshore fields with good track records; laboratory testing guides and industry standard protocols are well documented. However, it is worth noting that a scale inhibitor evaluation requires consideration of the specific challenges that the chemical may experience.

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As an example, the items below provide a brief introduction to each of the tests and the necessity of chemicals meeting the requirement of such tests (10)). Extended Stability

Thermal Stability: Temperatures for a specific field range from up to 40° C (104° F) at topside, 4° C (39° F) at the subsea wellhead, and >100° C (212° F) in the production stream. Consequently, thermal stability over a 28-day period over this temperature range is required. Any phase separation, precipitation, or solids deposition disqualifies the product for deepwater application.

Umbilical Stability: The extended reach of the subsea umbilicals leads to longer residence times and longer exposure to the deepwater environment. Stability of the production chemicals under these conditions is paramount to maintain the integrity of the injection system and the performance of the product. Specially-designed testing is needed to simulate the umbilical conditions. Any product degradation, precipitation, or solids deposition disqualifies the product for deepwater application. Umbilical Stability Tests Candidate products were exposed to a high-pressure flow loop with cyclic temperature variations using a special flow loop designed to simulate deepwater conditions (Figure 1). Each sample is continuously circulated in the flow loop for a period of 24 hours at 4000 psi (27,579 kPa). The samples are exposed to a temperature range between 100° C (212° F) and 4° C (39.2° F) while passing through a two-micron filter at two stages of the flow loop. Two inline filters (2 microns) collect particulates created as a result of product breakdown. Five inline pressure transducers monitor the pressures at critical locations along the loop. After circulation within the flow loop, the appearance of the sample is noted, looking specifically for any signs of precipitate and phase separation. The high-pressure flow loop assesses a number of criteria, including stability, separation, and filter plugging. Any increase in pressure indicates that the product is unstable at high pressure and unsuitable for deepwater application.

Figure 1: Schematic of the flow loop apparatus.

After circulation within the flow loop, the sample is inspected for signs of precipitate and phase separation. Samples are then evaluated for rheology profile and inhibition performance.

High Pressure Rheology Typically, chemical injection lines are bundled into subsea umbilicals of 0.64 to 1.27 cm (1/4 to 1/2 inches) in diameter. The associated back pressures and shear rates placed upon the production chemicals are now greater, which limits a chemicals maximum viscosity.

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A high-pressure rheometer is used to evaluate viscosities under the field pressure and shear rate conditions (Figure 2). Under typical subsea umbilical conditions (4° C (39.2° F) and 5000 psi (34,474 kPa)), the required viscosity is <100 cP (0.1 Pa.s).

Figure 2: Instrument for high pressure rheology measurement. Extended Compatibility

Fluids Compatibility: Each umbilical normally consists of several chemical injection lines. If the umbilical becomes damaged, there is the possibility that production chemicals will mix. Furthermore, since the bundled nature of these injection lines usually means adding several production chemicals in the vicinity of one another, the entire suite of production chemicals must have some degree of compatibility or sufficient dispersibility to avoid excessive interaction with each other. Therefore, chemical compatibility needs to be assessed before deployment at both seabed and injection temperature. Although production chemicals are not required to be completely compatible, this information is used by the operator to anticipate and solve incompatibility problems with the design or should an umbilical become damaged. Ideally a production chemical should be compatible with the produced fluids, but this may not always be possible.

Materials Compatibility: The compatibility of the production chemicals with injection system elastomers and metallurgy should be assessed before the chemical is applied. Failure of an injection line due to chemical incompatibility could render an entire umbilical non-functional. Typically, production chemical compatibility is assessed with all materials the chemical will contact at 70° C (158° F) for 14 days. Examples of such materials include: UNS*1 G10180 Carbon steel, UNS S31600, UNS S32205, UNS S32750, UNS C51000, EPDM, Buna N, Nitrile, PTFE, PEEK, HDPE, Nylon 11, Viton B†2, and Neoprene.

Compatibility with Umbilical Flushing Solvent: There is a risk of precipitation and blockage in subsea chemical injection lines with flushing solvents. Therefore, a solvent that can be used to remove any potential blockage needs to be identified before the product chemical is applied. Another consideration is that umbilicals are typically installed with installation/commissioning fluids. These fluids are displaced upon initial startup. Chemicals must also be compatible with these fluids or a multi-step procedure with spacer fluids should be designed.

Production Chemical Cleanliness: To further minimize umbilical blockage risks, all deepwater products are blended to meet the NORSOK Subsea Standard specification for cleanliness, NAS 1638 Class 6 and ISO 4406 Classes 15/12 (9).

*Unified Numbering System for Metals and Alloys (UNS) †Trade Name

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Extended Performance Evaluation Exposing a production chemical to high pressures or extreme temperatures for a prolonged period can reduce product performance; some chemicals may degrade under these conditions. Therefore, testing of product functionality after exposure is required to ensure product performance during production. Special lab testing equipment is needed to simulate the deepwater conditions that production chemicals experience. Any significant performance degradation due to exposure will disqualify the product for use in deepwater fields.

Figure 3: Inhibitor Testing Results Example Each of the four variations of the same chemical product was evaluated using the DSL (Dynamic Scale Rig) equipment (Figure 3). Several dosages were trialled; Figure 3 shows one of the examples (test dosage of 25 ppm). At this test dosage, the inhibitor sample that was incubated at the high temperature (212° F (100° C)) (sample 100° C_25 ppm) showed the worst performance, followed by the post-loop sample, then the sample that had been incubated at 39.2° F (4° C). The best performer of the four was the baseline sample (standard 25 ppm) that showed the longest scaling time. Although no significant differences were seen from the other tests (i.e. no phase separation or precipitation; viscosity is acceptable), the incubation of inhibitor in high temperature ((212° F (100° C)) has resulted in poorer inhibition performance, which is likely caused by product degradation. This suggests that this product may not be suitable for certain deepwater applications. Production Chemical Hydrate Protection Water can be a major constituent in product formulations, introducing the risk of methane hydrate formation (11-12). Mixing can occur due to the design specification, for example, a Non-Return Valve (NRV) may not be gas tight or a system failure occurs because an isolation valve fails. Note that it is typical for NRVs not to be gas tight (9) . Due to the high pressures and low temperatures present in deepwater chemical umbilicals, there is a risk that hydrates may form if there is an ingress of gas into the umbilical. Consequently, deepwater production chemicals need to be formulated specifically to minimize the risk of hydrate formation in the chemical injection umbilicals. As illustrated in Figure 4, only two products (Products A and C) are computed to prevent hydrate formation for the worst operating conditions that the field may experience (i.e. T = 4° C and P = 5000 psi (34,474 kPa)). Products B and D fall into the hydrate formation region at this condition, and so these two products are not suitable for the subsea application.

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Figure 4: Coupon Corrosion Rates for Uninhibited Wells. Environmental Evaluation If an umbilical becomes damaged during an intervention, production chemicals may enter the marine environment. Therefore, environmental profile, in particular toxicity testing, is required to determine the effect a product will have on marine life. In summary, to identify suitable scale-inhibitor products applied subsea, a suite of tests have to be performed to provide the data necessary to evaluate product performance for the temperature, pressure, and circulation regimes experienced in the field.

DEVELOPMENT IN ANALYTICAL TECHNIQUES In a conventional onshore or dry well scale squeeze program, a single well is squeezed with a single scale inhibitor and the flowback is monitored by a simple analytical method such as Hyamine 1622†3 for turbidity and Inductively Coupled Plasma – Optical Emission Spectrometry (ICP-OES) for phosphorous. This approach involves quantifying a physical chemical parameter (such as turbidity and elemental phosphorous); it works well in very simple systems where a single scale inhibitor is used and where there are no interferences from the well or other production chemicals (13-17). When interferences are present, the data obtained can result in misleading conclusions, as the methods can overestimate or underestimate the residual levels present. For offshore wet tree squeeze treatments with subsea tiebacks and commingled wells, the ability to obtain a specific data set of scale inhibitor residual data from any single well can be extremely limited. The samples obtained from the commingled flowback will, in most cases, contain fluids from a mix of wells and will, therefore, contain a mix of scale inhibitor residuals from the squeezed wells. Although single well samples can be obtained by stopping production from other wells, this has significant commercial implications for the operator, and it does not guarantee a clean sample due to the variable residence time of the fluids in the flowback. The original High Pressure Liquid Chromatography with Charged Aerosol Detection (HPLC-CAD) methodology was, in its time, a generational step-change in

† Trade Name

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analytical methodology, where a specific polymeric scale inhibitor is able to be quantified uniquely in field samples that contain other sources of phosphorous, other oilfield chemicals, and other ions that can give a response such as turbidity (18-19). The standard HPLC-CAD method can separate scale inhibiting polymers from other production chemicals and brine ions. However, it is not possible to separate scale inhibiting polymers from each other, and therefore is still an analytical method that is most applicable in single well systems employing a single polymeric scale inhibitor (20-23). In a realistic subsea scale management program, each well in a commingled flowback could be squeezed with a different scale inhibitor. The analytical methodology employed should be able to detect the scale inhibitors uniquely in the commingled sample to give individual well data. This would allow management of the wells on an individual basis based on scale potential rather than an average over all the mixed wells. To obtain detection, quantification, and specificity in these applications, a further generational step-change in analytical methodology, Liquid Chromatography-Mass Spectrometry (LCMS) technique, was developed. It shows promising results in detecting different polymeric scale inhibitor chemistries within one single commingled sample (24). The proof-of-concept studies demonstrate that the methods can accurately and specifically quantify polymeric scale inhibitors in the presence of each other in a commingled flowback. This has opened the door to the individual management of wells in a subsea scale squeeze program.

MODELING TECHNOLOGIES

In the area of evaluation of scale risk, a number of prediction technologies have been developed over the years. Simple empirical calculations include the Stiff-Davis Index and Oddo-Thomson method; later commercial prediction software tools included MultiScale†4 (PetroTech†), ScaleSoftPitzer† (Rice Brine Chemistry Consortium†), and ScaleChem† (OLI Systems†). The basis of these software tools is thermodynamic (rather than kinetic) equations; they are more reliable in predicting the:

scale type

probability of scale formation

maximum scale amount A reliable model must consider the correct pressure-volume-temperature (PVT) behavior of all reservoir fluids under all conceivable sets of thermodynamic downhole conditions. At a minimum, this includes the gas flash behavior of the oil and water, as well as the CO2 partitioning between the oil and water phases. Carbonate scale prediction is, therefore, more challenging due to the CO2 evolving and partitioning into all three (water/oil/gas) phases during production (25) while including hydrocarbon into the calculation significantly increases carbonate scaling potential. Prediction results are only as good as the input data. Compositional analysis for both oil and gas at the water sampling/analysis condition should be obtained before an accurate scale prediction can be made. Accurate carbonate scaling prediction depends upon the reliable input of:

conservative properties o scaling ion concentrations

† Trade

Name

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o total alkalinity

non-conservative properties (change with T and P) o pH (pH increase has a profound effect to prompt calcium carbonate scaling potential) o CO2 mass balance in all three phases o GOR / GWR / GLR o Hydrocarbon analysis

It is essential to have a comprehensive understanding of reactions in all three phases (i.e. the total alkalinity and CO2 mass balance) to ensure an accurate prediction.

water analysis o Ion concentrations in mg/l. cations (Na+, K+, Mg2+, Ca2+, Ba2+, Sr2+, Fe2+) and anions (Cl–, SO42–,

HCO3–)

o pH o bicarbonate concentration (used as total alkalinity, this is only true in waters without other acids

rather than CO2)

oil and gas analysis data Many software packages mentioned are reliable. These scale prediction programs are thermodynamic “equilibrium” models in nature and do not provide information on the kinetics or rate of precipitation. Predictions that are based on thermodynamics are not always satisfactory because nucleation, kinetics of crystal growth, adhesion, and other factors are not considered. Only a few models incorporated kinetics parameters; however, there is no general consensus in relating to the kinetic rates of different scaling species at this moment in time. Considering only thermodynamic and kinetic treatment of crystal precipitation, normally we calculate an overdose of scale; we will almost never encounter more, but in many cases will encounter less than predicted. Field examples show that more accurate predictions of scale risk are achieved by the combined use of the scale prediction tool with other simulators. A recent development in this area includes the incorporation of reservoir simulation tools (e.g. Eclipse†, Streamline/Frontsim† (26)), geochemical models (e.g. Ion Reaction† model from Heriot-Watt University), statistical models (e.g. Principal Component Analysis† (27)), hydrodynamic models (e.g. PIPESIM† (28)), and computational fluid dynamics (CFD (28) models with a thermodynamic prediction tool. An accurate scale prediction method should consider not only the thermodynamic, kinetic, and hydrodynamic conditions leading to this precipitation of the scale-forming compound, but also all conditions leading to the adherence of the precipitated or precipitating compound. It is advisable to develop and utilize integrated modeling technologies to ensure a more accurate scale risk evaluation when predicting the scale deposition within a production network, where any changes in any of the production network components can affect the scaling environment. In the area of squeeze inhibitor placement, Squeeze V/VI† series software manufactured by Heriot-Watt University is widely used in the industry. Chemical inhibitor volumes, pre- and post-flush volumes, and shut-in times for treatment can be designed and optimized using this code. Moreover, isotherm can be derived according to the previous field treatment performance, and the re-squeeze treatment can be further optimized following the history match analysis.

SUBSEA HARDWARE

In order to address the challenges associated with subsea fields, various hardware technologies are being developed and applied in the area of scale control and management.

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Subsea sampling technology (29) has been developed to enable the collection of representative samples under isothermic and isobaric conditions subsea. Representative samples are taken using subsea hardware (sampling interface and sampling module) situated at the place of interest, followed by transport and analysis of samples under representative conditions by a team of experts (30) (Figure 5). This chain of sampling services allows the most reliable sample analysis undertaken, which then enables accurate scale prediction based on the most reliable analysis data.

Figure 5: The Subsea Sampling Journey from Subsea Field to Laboratory Analysis

In order to create easy well access without the need for use of an expensive rig, hardware technologies have been developed and applied in scale squeeze treatments. For example, a squeeze chemical can be re-injected via the MARS† (Multiple Application Reinjection System, manufactured by OneSubsea†5) insert within the choke body, rather than going through the production wellhead, thus allowing the scale treatment to be carried out using a light intervention vessel. This eliminates the need for rig use and well access through wellhead; millions of rig hire costs can be therefore saved, which results in significant OPEX savings in scale management. In order to control the chemical dosage to specific locations and/or individual subsea wells, the chemical injection metering valve (CIMV) has been developed and applied in scale control. This allows the correct inhibitor dosage to be injected to individual wells according to their specific scaling risk. Higher dosages can be selectively injected into high-scale risk wells while a smaller amount of inhibitor goes into low-scale risk wells. This is not only critical in terms of preventing scale in individual wells, but also in avoiding too much chemical being injected into low-risk wells.

CONCLUSION

This paper discusses the specific challenges associated with scale control and management in subsea fields; the various technologies developed and applied in scale management are reviewed and analyzed using examples from published papers.

† Trade Name

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Scale inhibitors used in subsea fields have to go through stringent laboratory testing protocols that replicate the harsh subsea environment. Extended compatibility and stability tests are required to ensure the scale inhibitors remain stable and do not negatively interact with subsea materials under large P/T variations and long residence times. Performance testing under representative field conditions monitors the aging of the chemicals under realistic field scenarios. Finally, hydrate proof testing and rheology investigations are performed under representative field conditions to confirm that there is no hydrate potential by water containing scale inhibitor itself, and to ensure that the flow rheology of the inhibitor is satisfactory even at harsh subsea environmental conditions. In order to enable the assessment of squeeze inhibitor performance and identify the re-squeeze times for individual subsea wells, analytical techniques have been developed to differentiate inhibitor species using a single commingled water sample. Third-generation polymer detection technique, based on LCMS technique, has shown some promising results in differentiating the scale inhibitor from different wells within a single sample. This allows more accurate estimation of re-squeeze time for wells with different water productions and different scaling risks. Various modeling techniques have been utilized in scale risk evaluation, and thermodynamic software programs mentioned above are widely used in the industry. Recent developments in integrated modeling show that combining other simulation tools (e.g. reservoir simulation, geochemical models, hydrodynamic models) with scale prediction software can provide more accurate risk evaluation, which is sometimes crucial in decision making. Advancements in subsea hardware, such as subsea sampling, the MARS system, and CIMV technologies, have been applied in the area of scale management. This enables use of the most reliable water analysis data in scale risk evaluation, huge OPEX savings (elimination of requirement for expensive rig and wellhead access during squeeze treatments for subsea wells), and allows for the injection of the most accurate scale inhibitor dosages into individual subsea wells under different scaling regions. All of these technology advancements help to identify where exactly the scaling water comes from (e.g. which formation zone), where the scale is likely to be deposited, and what are the most cost-effective way of managing it. Further development in technology (laboratory, analytical, modeling, and hardware), will allow for better control of scale and could help reduce expenditures in the area of scale management in complex subsea field environments.

REFERENCES

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Paper No. 5480 - slb.com/media/Files/technical_papers/500/5480-NACE.… · NACE International, Publications Division, 15835 Park Ten Place, Houston, Texas 77084. ... laboratory testing