Abstract

With the increased use of 3-D fracture simulators, the need for accurate and affordable formation stress tests has arose. One of the main factors in keeping the test cost down is conducting the stress test with water. In most formations the stress gradient is high enough (i.e. >0.433 psi/ft) that water can be used, but there are many formations (Berea, Weir, Devonian Shale) that have stress gradients lower than 0.433 psi/ft. When this situation occurs the hydrostatic pressure of the water can fracture the formation and the well goes on vacuum. This leads to problems establishing constant injection rates and pressures that are usually obtained before monitoring pressure falloff. In the past, formations with low stress gradients used nitrogen for the test fluid, thus keeping the hydrostatic pressure below frac gradient. This method works but is extremely cost prohibited.

This paper explains the problems that can occur when testing low stress gradient formations, and procedures that can be used to gain accurate formation stress profiles using water and a downhole shutoff tool with equalizing ports.

Introduction

When formation stress tests are conducted with water, the standard procedure is to isolate the zone being tested with a bridge plug and packer or straddle packer. The formation is then broken down and a constant injection rate of 1/4 to 1/2 bpm is established. This rate is maintained until a constant injection pressure is reached, At this point a plug is lowered into a seating nipple, isolating the zone. A surface readout gauge monitors the bottomhole pressure below the plug so that the pressure falloff can be recorded and evaluated in real time. When the engineer has determined that the fracture has closed, the plug is pulled out of the seating nipple. The above procedure is repeated until the engineer feels that adequate data has been obtained. The packer is then released and moved to the next zone of interest.

In formations with stress gradients lower than 0.433 psi/ft, fracture propagation starts as soon as the zone is broken down, This is due to the hydrostatic pressure exerted by the column of fluid being greater than the natural stress gradient of the rock. Fluid will be injected into the formation until the fluid level in the wellbore has fallen to the point where the hydrostatic pressure equals the propagation pressure. Because the fluid level is changIng over time, the hydrostatic pressure is also changing. This causes the injection rate to gradually decrease as the fluid level falls and makes obtaining a constant injection pressure impossible. The uncontrolled injection also causes larger fluid volumes to be placed into the formation. Typically about 1/2 to 2 bbl of fluid is injected, but if the formation goes on vacuum as much as 20 bbls can be injected before equilibrium is reached. In low permeability zones these large fluid volumes can increase closure time by hours.

By using a downhole shutoff tool with equalizing ports, injection rates and pressures can be controlled while conducting stress tests with water in low stress gradient zones.

Stress Test Procedure

The first step in conducting an in-situ stress test is to perforate and isolate each zone. Standard practice is to shoot four shots in a one foot interval in each formation that is to be tested. A bridge plug and packer or straddle packer is then run on tubing to isolate each zone. The zones are usually tested from the deepest to the shallowest, but they can be done in any order. This procedure is the same for normally or underpressured zones. When a downhole shutoff tool is used an Otis XN seating nipple is placed above the packer making sure there is enough clearance for a pressure memory gauge (MRO) to be run on the bottom of the tool string.

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