Constraining the Conditions of Scale Deposition in a Gas Condensate Well: A Case Study
- R. A. McCartney (Oilfield Water Services Limited) | SPE, S. Duppenbecker (BP Exploration Co.) | R. Cone (BP Exploration Co.)
- Document ID
- Society of Petroleum Engineers
- SPE International Oilfield Scale Conference and Exhibition, 14-15 May, Aberdeen, Scotland
- Publication Date
- Document Type
- Conference Paper
- 2014. Society of Petroleum Engineers
- 4.3.4 Scale, 5.1 Reservoir Characterisation, 4.1.5 Processing Equipment, 5.6.5 Tracers, 2.2.2 Perforating, 5.2 Reservoir Fluid Dynamics, 2.2 Completion Installation and Operations, 4.1.2 Separation and Treating, 2 Well completion, 7 Management and Information, 5.5.11 Formation Testing (e.g., Wireline, LWD), 5.2 Reservoir Fluid Dynamics, 7.2.1 Risk, Uncertainty and Risk Assessment, 5.2.1 Phase Behavior and PVT Measurements, 7.2 Risk Management and Decision-Making
- Calcium carbonate, Formation water, Scale, Gas wells, Produced water
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Field X is a gas condensate field where the wells produce primarily gas and a small amount of formation water mixed with condensation water (<19 Sm3/d per well). Unexpectedly, scale (aragonite, possibly with minor sulfate minerals) was identified in Well A during a routine PLT. To aid scale mitigation planning, the cause of scale deposition has been investigated using scale prediction software.
A wide variety of data and information has been used to constrain and verify the scale predictions and as a result they are consistent with the observed type, volume and location of scale, PLT results (inflow temperature, hydrocarbon flow profile), produced water and formation water Ca and Cl concentrations, and production data (hydrocarbon and total water rates). A novel method was developed to estimate the composition of formation water entering the well from produced water analyses (mixtures of condensation and formation water) and where produced water rates are available this can also be used to estimate the rate of flow of formation water into the well.
The results suggest that formation water enters the well at low rates (~1m3) from the upper perforated zone (Formation 1) whilst water-saturated hydrocarbons enter from both the upper and lower zones (Formations 1 and 2). The formation water Cl concentration is between ~5, 100 and ~11, 000 mg/L and the Ca concentration may be between ~121 and ~177 mg/L. Partial evaporation of formation water (due to pressure decline and Joule-Thomson heating) as it enters the well causes scale deposition. The remaining formation water is produced along with water condensing from gas. An additional risk of total salt deposition in these wells was also identified.
This study has shown how a wide range of data can be used to constrain the conditions of scale deposition in such wells. The results of this study are being used to develop scale management plans for the field.
|File Size||3 MB||Number of Pages||16|