The Implication of HP/HT Reservoir Conditions on the Selection and Application of Conventional Scale Inhibitors: Thermal Stability Studies
Authors: Graham G.M. , Jordan M.M. , Graham G.C. , Sablerolle W. , Sorbie K.S. , Hill P. , Bunney J. 
Published: December 2007

G.M. Graham, SPE, M.M. Jordan, Heriot-Watt University, SPE, G.C. Graham, W. Sablerolle, Shell U.K. Exploration & Production, K.S. Sorbie, Heriot-Watt University, SPE, P. Hill, University of Manchester, and J. Bunney, SPE, Heriot-Watt University

In this paper, results are presented which highlight the problems associated with preventing scale and other mineral deposition in the new high pressure, high temperature (HP/HT) reservoirs which are currently under development in the North Sea and elsewhere. These HP/HT systems are characterised by very high salinity brines (TDS up to 300,000+ ppm), high reservoir temperatures &gt;175 C) and pressures up to 15,000 psi and above. A range of mineral deposition or "scaling" problems are expected for many HP/HT reservoirs. The current practice in conventional oil reservoirs is to treat produced brines with low levels of scale inhibitor in order to prevent mineral scale deposition within the tubulars or in topside equipment. However, in such harsh HP/HT environments, the currently used polymer and phosphonate scale inhibitor chemistries may not be appropriate due to a combination of factors including thermal stability and brine compatibility.

In this work, results are presented from static thermal stability tests conducted on conventional polymer and phosphonate scale inhibitors including phosphino-polycarboxylate (PPCA), polyvinyl sulphonate (PVS), sulphonated acrylate co-polymers (VS-Co), penta-phosphonate (DETPMP) and hexaphosphonate (Hexa-P). The paper focuses on the application (continual injection or squeeze) of scale inhibitor in these HP/HT reservoirs and the implications which this has for inhibitor selection. In addition, results from two "in situ thermal stability" coreflood experiments (at 175 C) are presented, using phosphonate and polyvinyl-sulphonate scale inhibitors, which give some indication of the in situ stability characteristics of these two species. These results help to determine the direction in which research should proceed in order to identify new scale inhibitor species for HP/HT applications.

Introduction

With the development of a number of new HT/HP fields in the North Sea, for example ETAP (Eastern Trough Area Project) and Elgin/Franklin reservoirs, a number of important "scale" control problems are expected. These HP/HT reservoirs are characterised by very high salinity brines (TDS up to 300,000+ ppm), high temperatures (T&gt;175 C) and pressures in the range 12,000 to 15,000 psi. The control of inorganic precipitates will be an important issue in the development and throughout the lifetime of many of these systems. Some previous experience of severe water chemistries (high temperature, high TDS) has been gained in the North Sea in the Gyda and Ula reservoirs, operated by BP. These reservoirs have similarities to the newer HP/HT environments in terms of their high TDS and moderately high downhole temperature; e.g. Ula T = 147 C, TDS&gt;300,000 ppm; Gyda T = 156 C, TDS 200,000 ppm. Although conditions in Ula and Gyda are not as severe as expected in several of the newer HP/HT fields, experience gained during the operation of these fields will be invaluable for tackling the problems of the newer more severe water chemistries. Table 1 presents a selection of the ion compositions of the formation brines found in several of these new HP/HT reservoirs compared with that from the Forties reservoir in the North Sea.

The Form of the "Scaling" Problem. In the new HP/HT reservoirs, various forms of inorganic precipitate are expected. These will include the common oilfield scales such as the insoluble barium/strontium/calcium sulphates and calcium/magnesium carbonates. In addition, the very high salinity of several of the formation brines (TDS &gt;300,000 ppm) can result in halite drop-out (NaCl(s)) either as a result of water flash-off into the gas phase as pressure decreases during production or simply due to reduced halite solubility as the temperature declines during production. Such problems associated with halite drop-out have been encountered occasionally on the significantly less severe Ula production system.

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