Deepwater Focus: Flow Assurance

Scale control in deepwater fields

Use an interdisciplinary approach to control scale.

Myles M. Jordan, Nalco; Eric J Mackay, Heriot-Watt University

Scale control in produced fluids is critical to the safe, economic, environmentally acceptable and effective production of hydrocarbons, as water follows the injection, production, processing and reinjection cycle in oil production facilities. This paper focuses on scale control in deepwater reservoirs, and describes scale control measures that are designed into the field development plan based on the integration of reservoir simulation, completion design technology, and production chemistry. Emphasis is placed on the life cycle of the field, and on the range of development scenarios, since money spent in the CAPEX phase is more than recovered in the OPEX phase of a field’s life.

BRINE CHEMISTRY

Oilfield scales are inorganic crystalline deposits that form by precipitation from brines in the reservoir and production flow system. The precipitation occurs due to changes in the ionic composition, pH, pressure and temperature of the brine. There are a wide range of solids that can interfere with the effective hydrocarbons recovery including: calcite (CaCO₃), siderite (FeCO₃), barite (BaSO₄), celesitite (SrSO₄), anhydrite (CaSO₄), gypsum (CaSO₄.2H₂O), pyrite (FeS), galena (PbS) and sphalerite (ZnS).

There are three principal mechanisms forming scales in offshore and onshore oilfield systems:

1) A decrease in pressure and/or increase in a brine’s temperature, leading to a reduction in salt solubility (these often precipitate carbonate scales, like calcium carbonate)

2) Mixing two incompatible fluids (usually formation water rich in cations such as barium, calcium and/or strontium, mixing with sulphate rich seawater to precipitate sulphate scales, such as barium sulfate)

Other fluid incompatibilities include sulphide scale, where hydrogen sulphide gas mixes with iron, zinc or lead rich formation waters, like sphalerite)

3) Brine evaporation, resulting in the salt concentration increasing above the solubility limit and leading to salt precipitation. This may occur in HP/HT gas wells where a dry gas stream mixes with a low-rate brine stream, resulting in dehydration and precipitation of halite (NaCl).

Details of these mechanisms are given elsewhere^{1 – 5}, as are the reasons why they pose problems in the production well, near-well areas and surface facilities^{6 – 8}, much less commonly in injection wells⁹ and never deep within the reservoir^{10 – 12}. The techniques available for scale control may be divided into four categories: selection of injection fluid source, chemical inhibition, chemical/ mechanical remediation and flow conformance. Details of these techniques are given elsewhere.^{1,13 – 30}

Engineers can determine basic scale risk during hydrocarbon production by the assessment of the scale mass and supersaturation that can form, based on brine chemistry during ideal mixing of formation and injection fluids, the physical changes in the mixing ratio and the environment that the fluids will encounter (Fig. 1). Simulations can be run with commercial software such as Scalechem, Multiscale, OKScale and Scalesoft using brine analysis from representative samples along with injection fluid composition.

Fig. 1. Basic scale risk assessment includes identifying scale types in many production environments.

PLACEMENT

If scale control is required for a field development, then its deployment is critical. Based upon industry experience, a scale inhibitor deployment (well intervention) index can be calculated, which ranks the difficulty of performing a squeeze treatment and successfully placing chemicals. The index is a composite formed by multiplying two factors: well access difficulty and the completion nature. The difficulty index has a scale of 1 to 12 with 1 being the easiest.^9,38

North Sea fields are predominantly low-angle wells and are generally cased and perforated. Most future deepwater developments will be done with subsea wells. The wells will be a mixture of moderate angle (60°) to very high angle. Many of these wells will be openhole gravel packs and openhole frac packs, which add to the challenge of effective chemical placement. A range of industry data has been compiled and plotted in the form of a risk matrix of scale risk against intervention difficulty⁹ in Fig. 2.

Fig. 2. This matrix shows the scale formation risk versus the intervention difficulty for current BP fields, selected industry data and future BP developments.

SCALE RISK PREDICTION/ ASSESSMENT

During the development of a scale management program there are two design assessment levels. The basic assessment relies on determining the scale mass and supersaturation of the brine chemistry to predict scale occurrence and control difficulty using chemical or non-chemical treatments.^9,38 A more advanced risk assessment process has been developed which uses reaction transport modeling of the injection and formation brines between injection and production wells.^{8,39 – 44} To provide data for the risk assessment process, reservoir simulation models may provide expected water production rates, provide water flow profiles along the wells during production and treatment stages, and to evaluate potential squeeze treatment performance.⁴⁴

The models may be adapted to investigate the reaction processes in the reservoir, and their impact on brines’ scaling tendencies as they reach the production wells and near-well formation. In sandstone reservoirs, some brine mixing occurs within the reservoir. The degree of mixing is a function of layering, and whether the brine mixing occurs in the oil leg or the aquifer. There is very little effect on flow behavior deep within the reservoir. However, for sandstone reservoirs a proportion of the scaling cations are removed, which reduces the scaling tendency when the brines break through to the production wells.

A similar, though more complex, situation exists in carbonate reservoirs. Here sulphate ions are removed deep within the reservoir, reducing the scaling risk at the production wells.

Thus, reservoir simulation addresses two key questions: what is the impact of brine mixing deep within the reservoir, and how effectively can scale inhibitor squeeze treatments be designed?

To calculate the effect of in situ precipitation, the dataset was converted to a commercial finite difference and reaction transport model. During both conversion stages, engineers ensured that the models were consistent with the original models. Good matches were achieved for both conversion stages.

Reservoir simulation models can provide expected water production rates and water flow profiles along the wells during production and treatment.⁴⁴ A scale control program should be designed in the CAPEX stage of a project and includes:

1. Brine sample analysis for scaling potential
2. Scale inhibitor testing to identify the best chemistry
3. Fields analog studies for scaling risks and management
4. Field reservoir simulation models to predict seawater breakthrough and seawater production duration
5. Well-by-well analysis of predicted seawater production profiles and total water production rates for the correct placement of inhibitor by bullhead treatments in zones at risk of scale deposition
6. Reservoir modeling to study the impact of in-situ scale deposition on brine chemistry at the production wells, and revision of squeeze treatments
7. Economic analysis of scale management options.

FIELD EXAMPLE

Scale prediction and assessment during reservoir stripping has great value in both the CAPEX and OPEX phases of a field’s life cycle. The following example shows the value that scale ion stripping has brought to the scale management of a mature North Sea field. As was outlined in the basic scale risk assessment, scale ion stripping normally follows the process of scale risk assessment for sulphate scale by assuming ideal mixing of formation water with seawater.

The field’s production wells are completed in multiple formations, so that a combined brine chemistry is produced. Table 1shows formation water chemistries from three wells in North Sea field that produces from discrete layers. Figs. 3 and 4 show the mass and supersaturation of barium and strontium sulphate scales under reservoir conditions (93°C, 3,500 psi) during the breakthrough of injection seawater. Calcium sulphate was not predicted for any of the formation injection brine mixtures. Formation water from wells A, B and C were used to assess the minimum inhibitor concentration (MIC) expected for a phosphonate scale inhibitor with different ratios of injection seawater and formation water. The current produced water chemistries for Wells A, B and C are in Table 2. The seawater fraction in these wells ranges from 16% at Well A to 53% at Well B.

Fig. 3. Barium sulphate mass and supersaturation predicted for Wells A, B and C in the North Sea vary with seawater concentration.

Fig. 4. Strontium sulphate mass and supersaturation predicted for Wells A, B and C in the North Sea peak near 50% seawater.

Laboratory assessment of the MIC values revealed that 5 – 7.5 ppm was required for Well A up to 20 – 25 ppm for Well C. From a review of scale prediction (Table 3) and the scale prediction for each well, the mass/ supersaturation for these three wells is much lower than predicted from ideal mixing. The impact of reservoir stripping for this field greatly reduced the MIC values required for scale squeeze treatments, which extended the treatment life-times and reduced chemical costs.

INTEGRATED RISK ASSESSMENT PROCESS

Knowledge of the reservoir flow paths, well completions, scale prediction, chemical selection and monitoring of the resulting treatments all aid effective scale management. These skill sets do not reside within one individual or department, so an integrated approach is required.

CAPEX/ OPEX scale management team
In any field’s life cycle there are two distinct phases: CAPEX and OPEX. During the CAPEX phase, decisions are made that will significantly influence the OPEX, and as a result, it is essential that all the scale control options are investigated that will keep OPEX to a minimum. The skills to assess the risk of scale formation and how it impacts the economics of a project do not reside with one individual or department (Fig. 5). A team approach is needed and should include the following specialties and duties:

Fig. 5. Scale management during CAPEX requires splitting the responsibilities between members of an interdisciplinary scale management team.

1. Reservoir and subsurface engineering is responsible for the location of the production and injection wells, the type of completion and the assessment of the possible scale control options.
2. Reservoir simulation and scale prediction identifies the possible extent of reservoir stripping of scale ions and the composition of produced brine chemistry with time and along each wellbore, which influences the scale control options and the possible effectiveness of the chemical treatment options.
3. Scale control application specialist/ pre-application laboratory assessment identifies possible scale control programs, and application methods to find the most effective deployment methods and chemical type.
4. Topside process and facilities engineering determines changes in the topside process and facility engineering including: pump sizing, capillary lines, squeeze injection pumps, umbilical lines, deck space issues and power for desulphated seawater plants, and the location of produced fluid samples points.
5. Chemical coordinator and production chemistry selects the materials supply chain and assesses the environmental impact.
6. Onshore/ offshore laboratory carries out basic measurements required for injection water quality and its fraction of breakthrough brines. Real time monitoring³⁴ for assessment of brine scale risk and measurement of suspended solids³³ from production wells will help evaluate the performance of scale control programs. The onshore laboratory facility should provide routine analysis for 12 ions, scale inhibitor residuals, suspended solids evaluation via scanning electron microscopy.

Similar specialists and duties are needed on the OPEX scale management team.

CONCLUSIONS

Scale types and deposition locations vary depending on the physical condition within the production environment and the produced water composition. Scale formation and the control methods needed are constantly changing through a field’s life cycle. Scale risk prediction has been developed to accurately assess the impact of scale formation and the cost of control options at the CAPEX phase to accurately reduce cost during the OPEX phase. Constant assessment by monitoring evolving brine chemistry and suspended solids can improve the confidence in the scale control program and reduce MIC values for wells or the process environment. 

ACKNOWLEDGEMENTS

The authors thank Nalco and Heriot-Watt University for permission to publish. We also acknowledge the members of the asset teams for their assistance in carrying out the evaluations and treatments described. The assistance of Clare Johnston, Morag Robb and David Marlow at Nalco is appreciated. This article is based on SPE 94052, presented at the 14th Europec Biennial Conference June 13 – 16, 2005, in Madrid, Spain.

LITERATURE CITED

1. Oddo, J.E. and Tomson, M.T., “Why Scale Forms in the Oil Field and Methods to Prevent It,” SPE Production and Facilities, Feb. 1994. pp. 47-54.
2. Ramstad, K., Tydal, T., Ellersten, E. and Jakobsen, T., “Precipitation and Deposition of CaCO₃. Laboratory Studies and Field Experience,” presented at the 1999 NIF Tenth International Oil Field Chemicals Symposium, Fagernes, Norway, March 1-3.
3. Vetter, O.J., Kandarpa, V. and Harouaka, A., “Prediction of Scale Problems due to Injection of Incompatible Waters,” JPT, Feb. 1982, pp. 273-284.
4. Jacques, D.F. and Bourland, B.I., “A Study of Solubility of Strontium Sulfate,” SPEJ, April 1983, pp. 292-300.
5. Vetter, O.J., Kandarpa, and Phillips, R.C., “Prediction of Deposition of Calcium Sulfate Scale under Down-Hole Conditions,” JPT, Oct. 1970, pp. 273-284, 1299-1308.
6. White, R., Brookley, J. and Menzies, N., “Practical Experiences of Gel Diversion Technique and an Overview of Scale Management for the Alba Field”, SPE Symposium on Oilfield Scale: Field Applications and Novel Solutions, Aberdeen, Scotland, Jan. 27 – 28, 1999.
7. Mackay, E.J. and Sorbie, K.S., “Brine Mixing in Waterflooded Reservoirs and the Implications for Scale Prevention,” SPE 60193, presented at the SPE 2nd International Symposium on Oilfield Scale, Aberdeen, Scotland, Jan. 26-27, 2000.
8. Sorbie, K.S. and Mackay, E.J., “Mixing of Injected, Connate and Aquifer Brines in Waterflooding and its Relevance to Oilfield Scaling,” Journal of Petroleum Science and Engineering, July 2000, v. 27 (1-2), pp. 85-106.
9. Mackay, E.J., Collins, I.R., Jordan, M.M. and Feasey, N., “PWRI: Scale Formation Risk Assessment and Management,” SPE 80385, presented at the SPE 5th International Symposium on Oilfield Scale, Aberdeen, Scotland, Jan. 29-30, 2003.
10.  Bertero, L, Chierici, G L, Gottardi, G, Mesini, E. and Mormino, G., “Chemical Equilibrium Models: Their Use in Simulation the Injection of Incompatible Waters,” SPE Reservoir Engineering, Feb. 1988, pp. 288-294.
11. Paulo, J. and Mackay, E.J., “Modelling of In-Situ Scale Deposition,” presented at the 12^th International Oil Field Chemical Symposium, Geilo, Norway, April 1-4, 2001.
12. Mackay, E.J.: “Predicting In-Situ Sulphate Scale Deposition and the Impact on Produced Ion Concentrations,” Trans IChemE, March 2003, v. 81 (A), pp. 326-332.
13. Hinrichsen, C.J., “Preventing Scale Deposition in Oil Production Facilities: An Industry Review,” paper 61, presented at NACE Corrosion 98, Houston, Texas, 1998.
14. Clemmit, A.F., Hunton, A.G., and Riley, B., “The Dissolution of Scales in Oilfield Systems,” SPE 14010, presented at the 1985 Offshore Europe Conference, Aberdeen, Scotland, Sep. 10-13, 1985.
15. Mendoza, A., Graham, G. M. and Sorbie, K.S., “Sulphate Scale Dissolution: Examination of the Factors Controlling the Effectiveness of EDTA and DTPA based on Scale Dissolvers and their Comparative Effectiveness against Different Sulphate Minerals,” presented at the 10th NIF International Oil Field Chemical Symposium, Fagernes, Norway, Feb. 28-March 3, 1999.
16. Tanner, R.N. and Wittingham, K.P., “Scale Control During Waterflooding Operations: A Field Appraisal of Inhibitor Requirements and Performance,” SPE 14127, 1986 SPE International Meeting on Petroleum Engineering, Beijing, China, March 17-20, 1986.
17. Børeng, R., Sorbie, K.S. and Yuan, M.D., “The Underlying Theory and Modelling of Scale Inhibitor Squeezes in Three Offshore Wells on the Norwegian Continental Shelf,” presented at the 1994 NIF International Oil Field Chemicals Symposium, Geilo, Norway, March 20-23, 1984.
18. Collins, I.R., Stewart, N.J., Wade, S.R., Goodwin, S.G., Hewartson, J.A., Deignan, S.D,: “Extending Scale Squeeze Lifetimes Using a Chemical Additive: From the Laboratory to the Field,” presented at the 1997 Solving Oilfield Scaling Conference, Jan. 23-24, 1997.
19. Bourne, H.M, Booth, S.L. and Brunger, A., “Combining Innovative Technologies to Maximize Scale Squeeze Cost Reduction,” SPE 50718, presented at SPE International Symposium on Oilfield Chemistry, Houston, Texas, Feb. 6-19, 1999.
20. Jordan, M. M., Sjuraether, K., Collins, I.R., Feasey, N.D. and Emmons, D,: “Life Cycle Management of Scale Control within Subsea Fields and its Impact on Flow Assurance, Gulf of Mexico and the North Sea Basin,” SPE 71557, presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, Sep. 30- Oct. 3, 2001.
21. Hardy, J. A. and Simm, I, “Low Sulfate Seawater Mitigates Barite Scale,” Oil and Gas Journal, December 2, 1996.
22. Davis, R., Lomax, I. and Plummer, M., “Membranes Solve North Sea Waterflood Sulfate Problems,” Oil and Gas Journal, pp. 59-64, 25 November 1996.
23. Vu, V.K., Hurtevent, C. and Davis, R.A., “Eliminating the Need for Scale Inhibition Treatments for Elf Exploration Angola's Girassol Field,” SPE 60220, presented at the SPE 3rd International Symposium on Oilfield Scale, Aberdeen, Scotland, Jan. 30-31, 2001.
24. Wylde, J. J., Allen, G.C. and Collins, I. R., “Comparative Study of Two Sulfate Scale Control Methods,” World Oil, v. 223, pp. 69-80, Oct. 2002.
25. Norris, M., Perez, D., Bourne, H.M. and Heath, S.M., “Maintaining Fracture Performance Through Active Scale Control,” SPE 68300, presented at the SPE 3rd International Symposium on Oilfield Scale, Aberdeen, Scotland, Jan. 30-31, 2001.
26. Collins, I. R., Jordan, M. M., Feasey, N. and Williams, G.D., “The Development of Emulsion-Based Production Chemical Deployment Systems,” SPE 65026, presented at the SPE International Symposium on Oilfield Chemistry, Houston, Texas, Feb. 13 – 16, 2001.
27. Cramer, R. W. and Bearden, J. L., “Development and Application of a Downhole Chemical Injection Pump for use in ESP Applications,” SPE 14403, presented at the SPE 60^th Annual Technical Conference and Exhibition, Las Vegas, Nevada, Sept. 22-25, 1985.
28. Fleming, N., Stokkan, J. A., Mathisen, A. M., Ramstad, K. and Tydal, T., “Maintaining Well Productivity through Deployment of a Gas Lift Scale Inhibitor: Laboratory and Field Challenges,” SPE 80374, presented at the SPE 5th International Symposium on Oilfield Scale, Aberdeen, Scotland, Jan. 29-30, 2003.
29. Shirah, A. D., Place, M. C., and Edwards, M. A., “Reliable Sub-Sea Umbilical and Down-Hole Injection Systems are an Integral Component of Successful Flow Assurance Programs,” SPE 84046, presented at the SPE 78^th Annual Technical Conference and Exhibition, Denver, Colorado, Oct. 5-8, 2003.
30. Wylde, J.J., Williams, G.D.M., Careil, F., Webb, P. and Morris, A., “Deep Downhole Chemical Injection on BP-Operated Miller: Experience and Learning,” SPE 92832, presented at the SPE International Symposium on Oilfield Chemistry, Houston, Texas, Feb. 2-4, 2005.
31. Jordan, M.M, Sjursaether, K, Edgerton, M.C and Bruce R., “Inhibition of Lead and Zinc Sulphide Scale Deposits Formed During Production From High Temperature Oil and Condensate Reservoirs,” SPE 64427, presented at SPE Asia Pacific Oil and Gas Conference and Exhibition, Brisbane, Australia, Oct. 16-18, 2000.
32. Collins, I. R and Jordan, M. M., “ Occurrence, Prediction and Prevention of Zinc Sulfide Scale within Gulf Coast and North Sea High Temperature/ High Salinity Production Wells,” SPE 68317, presented SPE Third International Symposium on Oilfield Scale, Aberdeen, UK, Jan. 30-31, 2001.
33. Jordan, M. M, Buckman, J. and Johnston, C. J., “ Direct Monitoring of the Performance of Scale Control Program Across the Produced Water Life Cycle Via Suspended Solids Analysis,” SPE 93892, presented at the 6^th European Formation Damage Conference, Schevevingen, the Netherlands, May 25-27, 2005.
34. Jordan, M. M, Archibald, I., Donaldson, L., Stevens, K. and Kemp, S., “Deployment, Monitoring and Optimization of Combined Scale/ Corrosion Inhibitor with a Subsea Facility in the North Sea Basin,” SPE 80214, presented at the Symposium on Oilfield Chemistry, Houston, Texas, Feb. 5-7, 2003.
35. Andersen, K. I., Halvorsen, E., Sælensminde, T. and Østbye, N.O., “Water Management in a Closed Loop – Problems and Solutions at Brage Field,” SPE 65162, SPE European Petroleum Conference, Paris, France, Oct. 24-25, 2000.
36. Graham, G. M. and Collins, I. R., “Assessing Scale Risks and Uncertainties for Subsea and Marginal Developments,” SPE 87460, presented at the SPE 6th International Symposium on Oilfield Scale, Aberdeen, Scotland, May 26-27, 2004.
37. Collins, I. R., “Predicting the Location of Barium Sulphate Scale Formation in Production Systems,” SPE 94366, presented at the SPE International Symposium Oilfield Scale, Aberdeen, UK, May 11-12, 2005.
38. Collins, I. R., “Scale Management and Risk Assessment for Deepwater Developments,” World Oil, v. 224, pp. 62-69, May 2003.
39. Mackay, E. J., Jordan, M. M. and Torabi, F,: “Predicting Brine Mixing Deep Within the Reservoir, and the Impact on Scale Control in Marginal and Deepwater Developments,” SPE 85104, SPE Prod. & Facilities, v. 18(3), pp. 210-220, Aug. 2003.
40. Mackay, E.J., “Modeling of In-Situ Scale Deposition: the Impact of Reservoir and Well Geometries and Kinetic Reaction Rates,” SPE 81830, SPE Prod. & Facilities, v. 18 (1), pp. 45-56, Feb 2003.
41. Mackay, E. J. and Graham, G. M., “The Use of Flow Models in Assessing the Risk of Scale Damage,” SPE 80252, presented at the SPE International Symposium on Oilfield Chemistry, Houston, Texas, Feb. 5-8, 2003.
42. Mackay, E. J., “Modelling of In-Situ Scale Deposition: the Impact of Reservoir and Well Geometries and Kinetic Reaction Rates,” SPE 81830, SPE Prod. & Facilities, v. 18(1), pp. 45-56., Feb. 2003
43. Mackay, E. J. and Jordan, M. M., “Natural Sulphate Ion Stripping During Seawater Flooding in Chalk Reservoirs,” presented at the RSC Chemistry in the Oil Industry VIII Conference, Manchester, UK, Nov. 3-5, 2003.
44. Mackay, E. J., Jordan, M. M., Feasey, N., Shah, D., Kumar, P. and Ali, S., “Integrated Risk Analysis for Scale Management in Deepwater Developments,” SPE 87459, presented at the SPE 6th International Symposium on Oilfield Scale, Aberdeen, Scotland, May 26-27, 2004.