Economic Optimum Operating Pressure for SAGD Projects in Alberta
Authors: Edmunds Neil , Chhina Harbir 
Published: March 2010

Introduction
During the recent Surmont gas-over-bitumen Alberta Energy and Utilities Board (EUB) hearing, a number of technical issues regarding the optimum operating pressure for steam assisted gravity drainage (SAGD) schemes were raised(1). From the evidence presented, the EUB concluded that there was a detrimental effect on SAGD recovery with decreasing gas pool pressure. The objective of this paper is to present technical and practical evidence of what is the most economical optimum operating pressure for a SAGD project in northeast Alberta.
We believe that the effect of operating pressure on SAGD recovery has been misunderstood, and that economics will in fact drive SAGD producers to develop low pressure recovery technology over time, regardless of the presence or status of contiguous gas caps.
We first present historical evidence that the high recoveries associated with SAGD will remain so at very low pressures. Secondly, analytical predictions of oil rate and steam-oil ratio (SOR) vs. pressure are considered. Finally, the effects of pressure on full-cycle scheme design and economics are calculated, based on simulation studies typical of oil sands reservoirs in northeast Alberta. The results support an economic optimum SAGD pressure in the range of 300 – 900 kPa.

Historical Steam Assisted Gravity Drainage Experience
and developed in Alberta. In reality, although Alberta may have been the first horizontal well application of SAGD technology, there are other examples of SAGD projects using vertical wells. In California, this has normally been referred to as steam flooding; but in a large number of those fields, gravity drainage has been a dominant recovery mechanism in comparison to other mechanisms, such as steam drag, steam drive, solution gas drive, thermal expansion, and steam distillation. Steam assisted gravity drainage in these fields has resulted in average oil recoveries exceeding 50% and as high as 85% OOIP(2–4).
An example is the Kern River field in California, one of the largest steam floods in the world. The formation depth varies from 300 – 1,400 ft. (90 – 430 m), initial reservoir pressure is 50 – 140 psig (345 – 965 kPag), oil gravity varies from 9 – 16 °CDATA [API, porosity is 35% and permeability varies from 1,000 – 7,600 mD(4, 5).
At Kern River, the primary production recovery ranged from 10 – 13% OOIP, but steam flood recovery ranges from 43 to 73 % of the pre-steam oil in place. Most importantly, the normal operating steam zone pressure during infill drilling was measured to be 6 psia (180 kPaa)(2). Another successful field example reported steam zone pressure of 40 psia (275 kPaa)(2).
It is the combination of very high recoveries and very low pressures which makes the case for gravity dominance in these cases; there are really no other plausible candidate mechanisms. The low operating pressures also give a clue as to the economics of low pressure gravity drainage: apparently, the operators consider the additional steam capacity they would require to raise the pressure to be an unattractive investment.
Greaser and Shore(5) reported on a number of steam flooding expansion projects in the Kern River field.