Scale control in deepwater fields: use an interdisciplinary approach to control scale

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 (CaC[O.sub.3]), siderite (FeC[O3]), barite (BaS[O.sub.4]), celesitite (SrS[O.sub.4]), anhydrite (CaS[O.sub.4]), gypsum (CaS[O.sub.4*].2[H.sub.2]O), 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)

Ca[(HC[O.sub.3]).sup.2] = CaC[O.sup.3] + C[O.sup.2] +[H.sup.2]O

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)

[Ba.sup.2+] (or [Sr.sup.2]+ or [Ca.sup.2+]) + S[O.sub.4.sup.2-] = BaS[O.sub.4] (or SrS[O.sub.4] or CaS[O.sub.4])

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

[Zn.sup.2+] + [H.sup.2]S = ZnS +2[H.sup.2+]

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.

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[degrees]) 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 difficulty (9) in Fig. 2.

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 1 shows 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[degrees]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.

[FIGURES 3-4 OMITTED]

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:

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 monitoring (34) for assessment of brine scale risk and measurement of suspended solids (33) 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.

[FIGURE 5 OMITTED]

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

A list of references is available at www.worldoil.com.

Dr. Myles Jordan is technical manager North Sea for Nalco. After earning his BSc in Geology and Chemistry at the University of Glasgow, Dr. Jordan studied for three years at Manchester University to earn his PhD in sedimentary geochemistry. He joined Heriot-Watt University in 1992, he was a senor research associate responsible for the day to day running of the Oilfield Scale Research Group Laboratory and for related contract research, e.g., on scale inhibitor evaluation, static adsorption, and reservoir condition dynamic coreflood studies. He has been an author or co-author of over 80 papers on adsorption/formation damages aspects of oilfield scale inhibitors. He is a committee member for both the SPE International Oilfield Scale Symposium and International Symposium on Oilfield Chemistry. Since joining Nalco in 1997 Myles has been responsible for managing Nalco's Technology Group in Aberdeen along with development of topside/downhole scale control programs while investigating new scale inhibitor molecules and novel application methods for scale control in vertical/horizontal wells.

Eric Mackay is a senior research associate at the Institute of Petroleum Engineering at Heriot-Watt University. His research interests include oilfield scale and modeling fluid flow in porous media, on which he has published over 50 papers. His responsibilities include teaching reservoir simulation. Mackay holds a BSc in physics from the University of Edinburgh. E-mail: eric@pet.hw.ac.uk.

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

TABLE 1. Brine chemistry for a number of formations within a North Sea
field.

                  Na+       K+     Ca++     Mg++     Ba++
Brine Type        mg/L     mg/L    mg/L     mg/L     mg/L

Average I Fm     23,788    511     1,262      212     212
Average II Fm    23,626    516     1,064      186     186
Average V Fm     23,420    290       810      110     120
Average VI Fm    22,400    160       955      145      86
Seawater         11,470    395       400    1,340       0

                 Sr++    Boron    Cl-       SO4--    HCO3-
Brine Type       mg/L    mg/L     mg/L      mg/L     mg/L

Average I Fm      245     44      40,113       11      710
Average II Fm     233     45      39,029       10      905
Average V Fm      200     58      38,230       26    1,020
Average VI Fm     195     54      34,960       23      645
Seawater            8      5      20,510    2,790      155

TABLE 2. Produced brine chemistry with seawater fraction calculated
based on chloride ion concentration for three North Sea wells.

                                 Na+       K+     Ca++     Mg++
Well code    Fm type    SW %     mg/L     mg/L    mg/L     mg/L

A              II        16     21,750    530     1,100    330
B            V + VI      53     18,780    435       815    410
C            I + VI      39     17,760    310       695    480

             Ba++    Sr++     Cl-      SO4--     pH      HCO3-
Well code    mg/L    mg/L     mg/L     mg/L     mg/L     mg/L

A             25      170    36,820     295      7.1      610
B             17      110    31,480     760      7.5      780
C             14       90    28,750     985      7.4      685

TABLE 3. Mass/supersaturation scale prediction and minimum inhibitor
concentration (MIC) measurements for ideal mixtures of brines from W
ells A, B and C along with the observed brine scale prediction
demonstrate the variation in corrective brine composition needed from
well to well. MIC values are after scale ion stripping.

                                          Mass
Current
Condition      Type of scale       Current    Theory

Well A        Barium Sulphate        35         225
Brine SW     Strontium Sulphate       0          0
@ 16%         Calcium Sulphate        0          0
Well B        Barium Sulphate        21         90
Brine SW     Strontium Sulphate      0.2       62.5
@ 53%         Calcium Sulphate        0          0
Well C        Barium Sulphate        25         217
Brine SW     Strontium Sulphate       0         90
@ 39%         Calcium Sulphate        0          0

              Scaling tendency          MIC (PPM)
Current
Condition    Current    Theory     Current    Theory

Well A         12         105        2.5       5-7.5
Brine SW        0        0.85
@ 16%           0         <1
Well B         25         142       2.5-5      10-15
Brine SW        1        1.59
@ 53%           0         <1
Well C         22         259       2.5-5      20-25
Brine SW        1         1.7
@ 39%           0         <1

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