ANÁLISIS DE LAS BITÁCORAS DE PROCESO

5.6.1 Leak Off and Formation Integrity Tests

A leak off test (LOT) is performed to determine the integrity of a cement bond and in doing so, determines the formation fracture pressure directly below the casing seat in the first formation after the casing shoe.

The zone directly beneath the casing seat is assumed to be the weakest point in the next hole section because it is the shallowest depth. Therefore, LOTs are usually performed after the casing is set and a small interval of the next section is drilled.

Before conducting a LOT, BOPs must be installed and the well must be closed-in. A small volume of mud is pumped slowly to gradually pressurize the casing; the surface pressure rises as this mud is pumped in.

As pressure increases, if the cement bond holds as is intended, then the formation is first to fracture. As fracture commences, mud starts to leak into the formation, and the rate of pressure increase drops off.

When a decrease in pressure is recorded, the test is complete.

Figure 46: Leak Off Test

Figure 46 illustrates the three pressure stages; it is the well operator’s decision as to which one is taken as the pressure on which to base subsequent calculations:

1. Leak off pressure—is the pressure at which fluid first starts to inject into the formation at the start of fracture. This is seen as a slight drop in the rate that the pressure is increasing. At this point, the pump rate should be reduced.

2. Rupture pressure—the maximum pressure the formation can sustain before irreversible fracture occurs. This is determined by a sharp drop in the pressure being applied, and pumping should be halted.

3. If no more pressure is applied at this point, most formations recover to a certain degree, and the propagation pressure is determined when the pressure becomes stable again.

The major disadvantage of the LOT is that the formation is actually being fractured and weakened during the test and the risk is that it may be permanently weakened or that a fracture may be opened. The formation generally recovers from the propagation pressure, but in reality this means that the fracture pressure has effectively been lowered and the pressure capabilities for the next hole section have been lessened.

When the formation at the casing shoe is fractured like this, there are two pressures acting on the formation causing the fracture, firstly the hydrostatic pressure because of the mud column and secondly the pressure that is being applied from the surface.

Therefore

Fracture Pressure = Mud Hydrostatic at shoe + Applied Surface (shut-in) Pressure

The use of this type of LOT is typically restricted to wildcat wells, for example, in an area where little is known about the fracture gradient and expected formation pressures.

Where offset data is available and fracture / formation pressures are known, a formation (or pressure) integrity test (FIT or PIT) is typically performed. This test is carried out in the same way as a leak off test, but the expected pressures and required maximum are known, so a predetermined surface pressure can be applied and held.

This predetermined pressure is gauged from offset well data and is determined so as to be sufficient for the largest pressure anticipated during the next hole section. There is a built-in safety margin in performing a FIT because the formation is not actually fractured during the test.

5.6.2 Repeat Formation Testing

Repeat formation testing (RFT), or wireline formation testing, is a quick and inexpensive way to sample formation fluids and measure hydrostatic and flow pressure at specific depths. Repeat formation testing provides the information required to predict formation productivity and to plan more sophisticated formation tests, such as drill stem tests.

Repeat formation tests can be run in open holes or cased holes through perforated production liners and multiple tests can be performed during one trip in the hole.

A spring mechanism in the RFT tool holds a pad firmly against the sidewall to form a hydraulic seal from drilling mud in the wellbore and a piston creates a vacuum in a test chamber. Formation fluids enter the

tool chamber through an open valve. The initial shut-in pressure is registered. The test chamber valve is then opened to allow the formation fluids to flow into it. A recorder logs the rate at which the test chamber is filled and then the final shut-in pressure is recorded. Because test chambers can hold only a tiny amount of formation fluid, a second sample chamber can be opened to draw more formation fluids.

5.6.3 Drill Stem Testing

Drill stem testing (DST) is conducted to record formation pressures and flow rates over large intervals of interest and to gather formation fluid samples to determine the potential productivity of a reservoir formation.

Drill stem tests can be run in open holes or cased holes through production liners which can be perforated to allow formation fluids to flow into the annulus.

Bottomhole DSTs are performed with a single packer that is set above the formation of interest. This isolates the zone between the packer and the bottom of the hole. This type of test minimizes the formation's exposure time to drilling fluid (because only one test can be run) and therefore minimizes the potential for formation damage.

Straddle drillstem tests, with dual packers, allow zones further up the hole to be tested. One set of packers is set above the formation of interest and the other below, thereby straddling the formation and isolating it for testing. This type of test offers the advantage that multiple tests can be run on the same trip into the hole and therefore keep costs down. However, there is greater potential for formation damage because of extended exposure to drilling fluid during multiple tests.

Tools employed in DSTs include the following:

 Packers—these are expandable rubber sleeves used to isolate the formation of interest. When they expand they form a seal against the wellbore wall, which prevents formation fluids from flowing through the annulus.

 Perforated pipe—allows the formation fluid to enter the drill stem during the flow periods of the test and then flow to the surface where they can be collected, stored, or burned off.

 Shut-in valve—controls the flow of fluid into the drill stem over a series of open-flow and shut-in periods. When closed, the shut-in valve stops the flow of formation fluid. When open, the shut-in valve allows the formation fluid to flow.

 Outside recorder—is set close to the perforated interval with the pressure sensor on the outside of the drillstring between the upper and lower packer. It measures pressure changes in the formation of interest during the test period, and provides the most accurate indication of reservoir pressure.

 Inside recorder—is set inside the DST assembly to measure the pressure of fluid entering through the perforated interval into the DST tool. The fluid recorder, or flow recorder, is set above the shut-in

fluid recovery.

A fourth, optional, recorder (called a below straddle recorder) is set below the bottom packer on straddle tests to measure how well the bottom packer seat holds.

5.6.3.1 Performing a Drill Stem Test

Drilling mud is circulated and conditioned to ensure the hole is clean and to reduce the possibility of cuttings or other debris damaging the DST tool. The DST tool is typically run into position on drillpipe. A cushion of water or compressed gas may be placed in the drill stem to support the drill stem against mud pressure until the test starts.

When the DST tool is in place, the packer is set to form a seal, usually by applying weight on the packer and the shut-in valve is opened. The cushion, if any, is bled off slowly to allow formation fluids to flow gradually into the drill stem and prevent formation damage caused by an abrupt flow. The wellbore is monitored throughout the DST for pressure changes that warn of poor packer seating. Most DSTs encompass two (and sometimes three) flow and shut-in periods (Figure 47).

The first flow and shut-in period, which is the shortest, clears out any pressure pockets in the wellbore and removes mud from the drill stem. The second and third flow and shut-in periods run longer than the first.

The purpose of the flow periods is to monitor the flow rate and changes in pressure. The shut-in periods serve to record formation pressure.

Figure 47: Drill Stem Testing (DST)

When the DST is complete, the shut-in valve is closed to trap a fresh, clean sample of formation fluid and the DST tool is unseated. Formation fluid is reverse-circulated out of the drill stem to prevent spillage while tripping out. The drillstring and DST tool are carefully tripped out of the hole, and the fluid sample and graphs are retrieved.

Information obtained in performing a DST includes: reservoir pressure, permeability, pressure depletion rates (volume and production rate), and gas, oil and water contacts. The saved sample provides valuable information on fluid saturation, viscosity, contaminants, and harmful gases.

Drillstem testing procedures are detailed more fully in Section 13.9.