Injectivity Testing in Underpressured Reservoirs
Authors: Sufi A.H. , Thompson R.J. 
Published: December 2007

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Abstract
A simple technique is presented to determine injectivity in underpressured reservoirs. This technique, called the Falling Head Test (FHT), allows calculations of kh and skin by utilizing type-curves developed for drillstem tests. Results from the FHT compare favorably with values obtained from conventional buildup tests. The tests cited in this paper were conducted in heavy oil reservoirs.

Introduction
In conducting engineering studies on heavy oil reservoir performance, it is necessary to identify the location, thickness and transmissibility of water zones. If the water leg is located high within the oil sand, it may cause excessive override of injected steam, in which case, the dominant reservoir mechanism would be a steam drag process. However, if steam can be injected and kept low in the reservoir, gravity drainage may become the dominant recovery mechanism. Location and thickness of water legs within oil sands can be obtained from logs. To determine the injectivity of these zones, injection tests have to be conducted and the subsequent pressure response analyzed. This paper discusses the application of pressure testing analysis as applied to underpressured heavy oil reservoirs and presents a modified DST technique to obtain formation transmissivities and wellbore skin.

WATER ZONES IN HEAVY OIL RESERVOIRS
Heavy oil reservoirs generally exhibit pore pressures lower than hydrostatic. This can be seen in many of the Canadian and California heavy oil and tar sands deposits. Further, the initial reservoir oil viscosity can be two to six orders of magnitude greater than that of any mobile water present in the reservoir. Consequently, if the water saturation of any zone is high enough, it can provide a large water flowrate compared to oil rates from richer oil zones. The high water saturation zone may also act as a conduit for injected fluids commonly used in thermal recovery. During steam injection, the presence of high mobility water zones may not be a detriment if the zones are placed low in the pay. In this case, the injected steam can enter low in the formation and create a heating pad which would allow for gravity drainage of the oil above.
However, if the zone mobility is excessively high, the injected steam could break through into neighboring producers quickly, resulting in an inefficient process. The mobility contrast between rich oil zones and any higher water saturation zones that may exist is greater in most of the Canadian heavy oil reservoirs. These reservoirs are, on the average, about 11C (20F) cooler than the California deposits, resulting in oil viscosities about an order of magnitude greater. Reservoir oil viscosities greater than 1000 cp are common, which does not allow economic cold production of the oil. These reservoirs have to be steamed from the onset to produce any oil. However, due to the low initial withdrawals from the wells, injection pressures rise quickly to formation breakdown pressures. If this does not present a problem, steam injection can be continued. However, if water sands exist nearby, the induced fracture could connect with them resulting in wasted heat during injection and/or rapid watering out of the well upon production. If higher water saturation zones exist within the deposits, they could be used to perform controlled injection into the reservoir.
To assess the transmissibility of zones present in the pay, it is necessary to conduct injectivity or productivity tests. However, as mentioned previously, many of the heavy oil reservoirs are underpressured and present wellbore storage problems during these tests. The next section discusses the types of pressure transient analysis used for underpressured reservoirs.
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