Squeeze Chemical for HT Applications--Have We Discarded Promising Products by Performing Unrepresentative Thermal Aging Tests?
- Rex M.S. Wat (StatoilHydro) | Lars-Even Hauge (StatoilHydro) | Kare Solbakken (Statoil) | Kjell E. Wennberg (StatoilHydro) | Linda M. Sivertsen (Statoil ASA) | Berit Gjersvold (Statoil)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Operations
- Publication Date
- August 2008
- Document Type
- Journal Paper
- 331 - 342
- 2008. Society of Petroleum Engineers
- 5.2.1 Phase Behavior and PVT Measurements, 4.1.2 Separation and Treating, 4.2.3 Materials and Corrosion, 4.3.4 Scale, 5.8.9 HP/HT reservoirs, 5.3.4 Reduction of Residual Oil Saturation, 5.2 Reservoir Fluid Dynamics, 4.3 Flow Assurance, 1.6.9 Coring, Fishing, 1.8 Formation Damage
- 0 in the last 30 days
- 352 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 12.00|
|SPE Non-Member Price:||USD 35.00|
Selecting an effective scale inhibitor for squeeze application at 170°C is not a simple task. The traditional thermal-stability test of aging the chemical in bulk is often perceived to be too harsh. This results in many promising products being rejected because of their apparent degradation at temperature. The alternative of conducting the aging test inside core materials, which is more representative of the downhole conditions, is not a novel idea. However, to date, no definitive data are available to substantiate such a process and quantify the difference between the two methods. This is mainly because of the difficulties and complexity in conducting such an experiment at a high temperature over a long period of time. In this paper, the results from a recent investigation are presented. We describe the detailed procedures of the planning and execution stages, lessons learned, and pitfalls that must be avoided. A scale inhibitor was aged with two different methods: one in bulk, as commonly practiced in the industry, and one inside a sandstone core. The aging period varied between 45 days for the bulk and 110 days for the last desorbed sample from the core. The samples that were aged inside the core retained much of their inhibition efficiency, while those aged by the traditional method (bulk) lost nearly all their effectiveness. These results demonstrate clearly that the conventional method of thermal aging in bulk is unrepresentative and that the loss in performance can be quantified. A novel finding from this study is the evidence of an unexpected relationship between desorption and inhibition effectiveness. The findings from this study could have great impact on selecting chemicals for high-temperature (HT) applications, even more so in those environmentally sensitive regions where the use of "yellow" (biodegradable) squeeze chemicals is mandatory. Many of these chemicals have been rejected because of their apparent thermal degradation, which has now proved to be unrepresentative.
In November 2005, Statoil began production from the Kristin field. Kristin is a high-pressure/high-temperature (HP/HT) gas/condensate field in the Haltenbanken area of the Norwegian Sea (see Fig. 1). It has the highest reservoir temperature (170°C) and pressure (911 bar) among the fields that Statoil is operating currently. Producing by natural depletion and with the formation water containing in excess of 2,500 ppm of calcium (Ca) and 900 ppm of bicarbonate (see Table 1), downhole CaCO3 scale deposition has been identified as one of the major production-related problems. From the early development phase, an active program to qualify suitable scale-control chemicals has been put in place, and it includes chemicals for squeeze treatment, wellhead continuous injection, and dissolver. For the squeeze chemicals alone, more than 110 products have been tested, 20 of which are considered to be yellow according to environmental classification by the Norwegian authority (Norwegian Petroleum Directorate 2002). Many of these were rejected because of poor performance, but many more of them were discarded because of their apparent thermal degradation at test conditions. This led us to review the current practice in the oil industry for thermal aging of chemicals and the validity of such results in the application in the field.
Most of the literature describing the thermal aging of squeeze chemicals was published in 1995 and the years that followed (Collins 1995; Graham et al. 1998, 2000; Audibert and Argillier 1995; Dyer et al. 1999). The enormous interest generated during this period was caused primarily by the Eastern Trough Area Project (ETAP) cluster development that included fields with a maximum downhole temperature of 180°C and a reservoir pressure of 885 bar. The screening technique relied mostly on the aging of chemicals in a sealed Teflon®-lined bomb over a period of 7 to 21 days. The extent of degradation was measured by their relative performance with respect to the fresh products. In these earlier studies, the focus was placed mostly on the effect of carrier-brine composition, pH, and oxygen level. The main degradation mechanisms were considered to be backbone scission and functional group degradation that were caused by hydrolysis and a free radical attack. A good overview of these mechanisms was presented in a recent publication (Kotlar et al. 2006), in which a refined technique for sample preservation and oxygen removal before the thermal-aging step was described.
Although this approach was considered to be a reasonable screening technique for the different products, doubt remained whether this was truly representative in the field because the chemical was not confined within a rock matrix. A number of papers did describe thermal aging inside core materials, where both outcrop sandstone (Graham et al. 1997, 2001a) and reservoir (Graham et al. 2001b) plugs were used. Typically, a small core plug was first saturated with the selected chemical and then the core was shut in at high temperature for a period of time. The intended samples (i.e., chemical aged inside the core) were collected afterward for comparative performance-tests. With a short core, the pore volume (PV) would be small, typically 7 mL for a 1-in.-diameter, 3-in.-length core with 18% porosity. If performance tests were to be carried out, these samples would need to be diluted many times. This would be limited to those effluents that had a high-enough concentration [i.e., the first 1 to 15 PV (24 hours) of the post-flush]. This was a short time frame compared to the actual squeeze life in the field. More importantly, the chemical that came out from the core during this period would have been trapped, more so than if they had been adsorbed. The degradation mechanism of the chemical molecules in a physically trapped environment was obviously quite different from that being hindered by a surface-binding interaction. Although yielding some results, such an approach would overlook the most critical part of the degradation process for a squeeze chemical (i.e., the combined effect of thermal aging and the surface-retention mechanism). It is this combined effect on which the current study focuses.
|File Size||1 MB||Number of Pages||12|
Audibert, A. and Argillier, J-F. 1995. Thermal Stability of SulfonatedPolymers. Paper SPE 28953 presented at the SPE International Symposium onOilfield Chemistry, San Antonio, Texas, USA, 14-17 February. doi:10.2118/28953-MS
Collins, I. 1995. Scale Inhibition at High Reservoir Temperatures. Paperpresented at the IBC Ltd. Conference on Solving Oilfield Scaling Problems,Aberdeen, 20-21 November.
Dyer, S., Graham, G.M., and Sorbie, K.S. 1999. Factors Affecting the ThermalStability of Conventional Scale Inhibitors for Application in HighPressure/High Temperature Reservoirs. Paper SPE 50717 presented at the SPEInternational Symposium on Oilfield Chemistry, Houston, 16-19 February.
Graham, G.M., Dyer S.J., Sorbie, K.S., Sablerolle, W.R., Shone, P., andFrigo, D. 1998. Scale InhibitorSelection for Continuous and Downhole Squeeze Application in HP/HTConditions. Paper SPE 49197 prepared for presentation at the SPE AnnualTechnical Conference and Exhibition, New Orleans, 27-30 September. doi:10.2118/49197-MS
Graham, G.M., Dyer, S.J., and Shone, P. 2000. Potential Application of AmineMethylene Phosphonate Based Inhibitor Species in HP/HT Environments forImproved Carbonate Scale Inhibitor Performance. Paper SPE 60217 presentedat the International Symposium on Oilfield Scale, Aberdeen, 26-27 January0 doi:10.2118/60217-MS
Graham, G.M., Dyer, S.J., Shone, P., Mackay, E.J., and Juhász,A.2001a. Comparative Core Flooding and Field Application Implications forScale Inhibitor Downhole Squeeze Treatments in High Temperature (374°F)Reservoirs. Paper SPE 65008 presented atthe SPE International Symposium on Oilfield Chemistry, Houston, 13-16February.
Graham, G.M., Dyer, S.J., Shone, P., Mackay, E.J, and Juhász, A. 2001b. High Temperature Core floodingExperiments for the Selection of Appropriate Scale Inhibitor Products forPotential Application as Downhole Squeeze Treatments in High TemperatureReservoir Environments. Paper SPE 68314 presented at the InternationalSymposium on Oilfield Scale, Aberdeen, 30-31 January. doi: 10.2118/68314-MS
Graham, G.M., Jordan, M.M., Graham, G.C. et al. 1997. The Implication of HP/HT ReservoirConditions on the Selection and Application of Conventional Scale Inhibitors:Thermal Stability Studies. Paper SPE 37274 presented at the InternationalSymposium on Oilfield Chemistry, Houston, 18-21 February. doi:10.2118/37274-MS
Harberer, A.L. and Brandes, J.A. 2003. A high sensitivity, lowvolume HPLC method to determine soluble reactive phosphate in freshwater andsaltwater. Marine Chemistry 82 (3-4): 185-196.doi:10.1016/S0304-4203(03)00069-0.
Kotlar, H.K, Hauge, L.E., Solbakken, K., Gangstad, A., Gjersvold, B., andSivertsen, L.M. 2006. Influence ofThermal Aging on Treatment Chemicals in HP/HT Applications: From Development ofEquipment to Field Application. Paper SPE 98337 presented at theInternational Symposium and Exhibition on Formation Damage Control, Lafayette,Louisiana, USA, 15-17 February. doi: 10.2118/98337-MS
Norwegian Petroleum Directorate. 2002. NPD/PSA Petroleum Regulations. http://www.npd.no/regelverk/r2002/frame_e.htm.
Richard, T., Detournay, E., Drescher, A., Nicodème, P., and Fourmaintraux,D. 1998. The Scratch Test as aMeans to Measure Strength of Sedimentary Rocks. Paper SPE 47196 presentedat SPE/ISRM Rock Mechanics in Petroleum Engineering, Trondheim, Norway, 8-10July. doi: 10.2118/47196-MS
Schei, G., Fjaer, E., Detournay, E. et al. 2000. The Scratch Test: An AttractiveTechnique for Determining Strength and Elastic Properties of SedimentaryRocks. Paper SPE 63255 presented at the SPE Annual Technical Conference andExhibition, Dallas, 1-4 October. doi: 10.2118/63255-MS
Suárez-Rivera, R., Stenebråten, J., and Dagrain, F. 2002. Continuous Scratch Testing on CoreAllows Effective Calibration of Log-Derived Mechanical Properties for Use inSanding Prediction Evaluation. Paper SPE 78157 presented at the SPE/ISRMRock Mechanics Conference, Irving, Texas, USA, 20-23 October. doi:10.2118/78157-MS