Abstract

The X Field steam-injection project is the world's first full-field steam-injection project based on thermally assisted gas/oil gravity drainage (TAGOGD) in a fractured carbonate field. The project scope includes drilling some wells and installing facilities to treat water and generate around 18,000 tonnes per day of steam. Additional facilities will be built to process the incremental oil and gas produced at the field as well as disposing of excess produced water in deep reservoirs. The EOR recovery process being applied TAGOGD is based on injecting steam into the formation's fractures to heat the low-permeability oil-bearing rock. This feature of the project allows the number of wells, and hence development costs, to be kept to a minimum. In other hand, the flow assurance issue across the facilities will be challenging, and managing scaling issues and inhibition require a host of solutions especially on the economics of scale management. A history of scaling as a lesson learnt had been gathered during Pilot steam back to a couple years ago and current cold production experiences is captured. At the moment, the incompatibility of various water stream indicated scaling deposition are majority dominated by carbonate and less sulphate. The strategy of integrated mitigation for all possible scaling for the next facilities scenario whether from water treatment and oil production facilities have been implemented and assessed during engineering design, while the type of inhibitor have been identified base on dynamic tube blocking tests and the potential risk have been registered. In the end, win-win economics approach is modeled base on water and fluid composition, various pressure and temperature.

Introduction

X Field is located in central Oman south of the western Hajar Mountains. This large oil accumulation is trapped in shallow Cretaceous limestone units at a depth of around 200–400m subsea. The anti-clinal structure is a result of a deep salt diaper, with significant crestal faulting and fracturing. The field was discovered in around 1970 and contained 16° API oil with a viscosity of 220cP has been produced from the 29% porosity, low permeability (5–14mD) limestone. During the primary production the first year showed a large peak in oil mainly from emptying of the fracture network with a minor contribution from fluid expansion due to pressure reduction. At the end of the first year, production had declined to a very low sustainable rate interpreted to be from gravity drainage, from a combination of gas-oil (GOGD) from the secondary gas cap and oil-water (OWGD) below the fracture gas-oil contact (FGOC). The reservoir then consists of a matrix with very little drainage and a fracture network with a thin oil rim below the secondary gas cap and above the fracture oil-water contact (FOWC), Figure 1.

Primary production performance such as that of X Field is only expected to recover some 3–5% of the oil in place over any reasonable time frame due to low matrix permeability and high oil viscosity on gravity drainage rates. Recoveries via steam were discounted as development options due to the pervasive fracturing observed in the field which would encourage the flooding agents to completely bypass the matrix.

Generally, formation of mineral scale associated with the production of hydrocarbon has been a concern in oilfield operation, especially on steam EOR (Enhanced Oil Recovery) operation. Depending on the nature of the scale and the fluid composition, the deposition can take place within the reservoir which causes formation damage or in the production facilities where blockage can cause severe operational problems. The two main types of scale which are commonly found in the oilfield are carbonate and sulphate scales. Meanwhile formation of carbonate scale is associated with the pressure and pH changes of the production fluid, the occurrence of sulphate scale is mainly due to the mixing of incompatible water stream.

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