A properly conducted and interpreted Drill Stem Test (DST) is the best diagnostic tool other than a production test for the evaluation of a prospective zone. The reservoir information derived from a DST is based on the actual “insite”, flowing conditions and represent average values for the depth or radius of investigation. Thus, a DST will provide superior information to other reservoir data obtained from a core or log analysis.
The following vital reservoir information can be derived from a DST:
128.Initial reservoir pressure.
129.Average permeability (for the radius of investigation). 130.Radius of investigation.
131.Formation damage by drilling fluids and whether stimulation may have application. 132.The location and effect of nearby reservoir heterogeneities such as faults, fractures,
permeability changes, or fluid contact. 133.An estimate of deliverability.
134.Nature of reservoir fluids.
135.Potential future production problems, i.e., sand production, sulphur deposition, hydrate formation, etc.
136.DST results
137.All original charts will be delivered to the testing company for detailed reading and preparation of the final test report.
138.A copy of the charts and test results will be immediately forwarded to Exploration Services by the testing company.
139.Drillstem test (DST) methods
There are generally three DST methods:
Open hole testing on the bottom of the hole.
This method is used as the well is drilled. The prospective zone is tested immediately after penetration by landing the test tools on the bottom, thus expanding the packers in compression. Two packers can be run in tandem for increased reliability.
Straddle testing in open hole.
This method can be used to test any interval in the open hole by hydraulically expanding a packer on each side of a prospective zone and testing the interval.
Cased-hole testing through perforations.
This is the most reliable method of testing a prospective zone, however, it is also the most costly as it requires setting and cementing the casing and perforating. Well control is safer during cased-hole testing, and allows higher differential packer pressures. This is the only method used in offshore exploration drilling.
There are several variations of the above methods, e.g., testing an open hole section below casing with the packers set in the casing.
The following points should be considered when conducting and planning a DST:
140.Service Company Selection
In some situations, such as deep hazardous wells, consideration must be given to testing companies with special tools, experienced personnel, and experience in the area, etc. Often these factors will influence the selection of the testing company to be used. 141.Amount of Open Hole to be Tested
In general, a more conclusive test is obtained by testing the shortest interval which is practical, e.g., if water is produced in the testing of a long interval, it is sometimes difficult to locate the portion of the interval which is producing water. It is usually best to limit the
interval to be tested to less than 20 metres. Another factor is that in testing deep gas wells, the test interval should be minimised to keep the gas influx left below the packer as small as possible. Gas influx below packers is just as dangerous on shallow wells. 142.Packer Type and Size
Packer size is governed by the size of the hole to be tested. Packer type is determined by the well depth and hole conditions. A harder packer rubber is required for deeper wells which exhibit high temperatures.
143.Location of Packer Seat
Open-hole packer seats should be selected in hard non-plastic formations such as hard sands, hard sandy shales, non-fractured lime or dolomite, or hard, dense non-fractured shales. Core and calliper log data, if available, will provide information on where to select a packer seat. Otherwise, cutting data must be used. A packer should never be set in an incompetent or sloughing shale zone above a prospective formation.
144.Top and Bottom Chokes
Normally, bottomhole chokes are run on all wells. On very high production wells larger than normal bottomhole chokes and tool internal diameters are required to obtain a draw down.
For deep wells, a bottomhole choke is required: 107.To limit the rate of gas produced,
108.To reduce the flowing pressure on drillpipe and surface equipment, and 109.To limit the differential pressure across the packer (200 - 280bar).
The choke is normally 3/8” to 1/2” which is small enough to achieve the above, but large
enough to avoid tool plugging.
The top choke should be initially fully open and reduced as flow, pressure, unloading of the water cushion, and safety dictate. The pressure upstream of the surface choke should be recorded throughout the test together with the choke size.
145.Probable Length of Flow and Shut-In Periods.
Where no guidelines are given the following times are suggested: Pre-flow - 5min., Initial Shut-in-90min., Final Flow -60min., Final Shut-In-180-min. Total time: 335min. (5.5 hrs.). Normal time requirements are 5-60-60-120. Normally two flow periods and two shut-in periods are required on a DST.
The initial flow or pre-flow should be five to ten minutes in duration. This can be
shortened if the air blow indicates a highly productive formation or lengthened if the air blow indicates a very tight formation. If there is no initial blow, attempt to reset the packers.
The initial build-up period is normally six to ten times the pre-flow period. Usually a sixty minute initial shut-in is adequate. If a weak air blow indicated a tight formation and the pre-flow period was extended to more than ten minutes, the initial shut-in period should be extended to ninety minutes.
A minimum of a 60-minute final flow period is used unless gas or fluid is flowed to surface. If gas is flowed to surface, the flow period is extended until a stable flow rate is attained. If fluid is flowed to surface, the tool should be shut-in immediately unless
are extended, the flow period should be extended to two hours. When sour gas is flowed to surface, the tool must be shut in immediately. In testing a deep well, it may be
necessary to shut the well in as soon as the water cushion reaches the surface so that there is no danger of drillpipe collapse.
The final shut-in period for highly permeable wells should be equal to the final flow period plus the initial shut-in period. For medium and low permeable wells, the final shut-in period should be one and a half to two times the final flow period.
146.Pressure Recorders
The pressure gauges should have a range equal to one-and-a-half times the expected hydrostatic pressure. There should be enough spare range to cover any shock pressures that may occur. A rough check on the gauge hydrostatic pressure can be made by comparing the pressure with the hydrostatic pressure calculated from the mud weight. If there is any doubt, then the gauges should be recalibrated and supplied with a revised set of calibration charts. The pressures from each recorder should also be compared carefully.
The data sheet accompanying each pressure chart should be marked with the position of the gauge, the pressure gauge serial number, the clock serial number, the on and off time for the clock, as well as other pertinent well data. Each clock run should have a range approximately equal to one-and-a-half to two times the maximum reasonable time the tools are to be in the hole. A temperature recorder should be run with each DST. The calibration and recording of the thermometer should be checked.
147.Reverse Circulating Sub
A reverse circulating sub should be run on all tests. It should be run at least nine metres above the top of the test tools. Care should be taken that it is not located opposite a gas sand. The hole should not be reversed out until such time as the packers have been unseated.
148.Safety Joint
A safety joint should be run with the test tools on all tests. 149.Jars
Jars should be run on all DST's regardless of depth. 150.Water Cushion
On tests of wells with depths greater than 2 750 metres, a water or nitrogen cushion must be run. However, if high pressure or high volumes are anticipated on a shallower well, a cushion may also be run. The main purpose of a cushion is to minimise:
110.Caving of the formation and sticking of the anchor pipe, 111.Plugging of anchor perforations and the bottomhole choke, 112.Packer failure, and
113.Drillpipe collapse on deep wells.
Enough water or nitrogen cushion should be run so that the differential pressure across the packer is in the range of 200 - 280bar.
For a deep well, the collapse rating of the drillpipe is also to be considered when
selecting the amount of water cushion. It should be remembered that the collapse rating of pipe varies considerably with the amount of tension in the pipe.
151.Surface Equipment
formation pressure.
A remote safety valve should be installed on the drillpipe at surface. On deep wells, consider provisions for a high-pressure pumping unit to be able to pump down the drillpipe.
The flare line should be drillpipe with a minimum 21/2” inside diameter (ID) and a burst
rating in excess of 200bar. All surface equipment and flare line connections should be thoroughly checked and tested before running a test.
The annulus should be continuously monitored during a test. The trip tank should be used for this purpose instead of visually watching the annulus.
152.Drillpipe Collapse and Burst
The collapse pressure rating normally quoted for drillpipe is with no tension. As tension increases, the collapse rating decreases. Burst pressure rating does not decrease with tension. However, the burst rating which is usually quoted for new drillpipe must be reduced to allow a safety factor for pipe condition and other unknowns.
In testing a deep gas well, it may be necessary to close the tool in before the water cushion is unloaded or, if not, to hold a backpressure on the drillpipe at surface to guard against collapse.
It should also be noted that when testing a deep gas well, if the well is shut in at the surface before it is shut in down-hole, then extremely high pressures could be
encountered at the surface. A bottomhole choke will only limit surface pressure under flowing conditions.
153.Drillstem test equipment
Run the minimum amount of equipment necessary, but always include three pressure recorders, one of which must be an outside recorder, a pump-out sub, a safety joint, jars, a sample chamber, and a fail-safe head loaded with a trip bar for the pump-out sub. Always run dual conventional packers. Run single inflatable packers if calliper log indicates excessive hole size or if more than one test of
common interval length is to be run on a single trip into the well. When running a straddle test, always run with a straddle by-pass assembly.
Consideration should be given to running an outside recorder below the bottom packer to check on the communication from below the packer if there is a possibility of by-pass plugging. Other
equipment, such as multi-flow equipment, tight hole subs, etc., is to be run only at the request of the head office. A separator and related surface equipment may be used if requested by the head office. Always run two shut-in tools, one hydraulic and one mechanical.
Always request that the testing company be equipped with a centrifuge to evaluate oil recovery, and has a means of determining the salt content of recovered water.
NOTE: The salinity of the mud should be determined from a representative mud sample
from the shale shaker tank prior to testing.
154.Wellsite preparation for drillstem testing
The hole should be conditioned prior to running a DST by circulating and completing a dummy trip to check for fill on the bottom. It is not necessary to raise the viscosity or adjust the mud properties to test. If the dummy trip and circulating indicate little or no fill, the hole is ready to test.
Strap out of the hole prior to all tests.
For tests run on the bottom, also check pipe tally as follows:
Before starting out of the hole, mark the kelly as it is with the bit on the bottom.
Measure all the pipe not used for the test, i.e., the part of the kelly in the hole, drill collars, etc.
Measure all tools and pipe picked up.
The difference between that laid down and that picked up should give the correct spot on the last single to find the bottom with the test tools.
For tests to be run off the bottom, pipe should be measured while running in the hole.
155.Ensure the correct tools have been delivered to the location and that they are in good condition. Check floor manifold and chicksans prior to running the test. Pressure test to at least the maximum anticipated bottomhole pressure. The flare line should also be checked and pressure tested to ensure no connections are leaking.
156.After the test tools have been made up, a sketch should be drawn showing the component parts, their lengths, and diameters. In addition, record details of the fishing necks, positions of the bombs, reverse circulating sub, and packer.
157.Making up the drillstem test tools and running in
The Company Representative must supervise the measurement of the tail pipe and test tools. Ensure that each item in the test string is included as requested and in its proper place. Check condition of packers prior to and after test.
Run the tools in slowly to prevent pressure surges on the formation. Running speed should be one minute or more per 27.5 metre stand.
When making up the tool and pipe, measurements should be taken to ensure correct packer location and to permit the last joint of pipe added to be marked at the point where it should be flush with the rotary when the packers are correctly in position. This allows the tools to be eased into contact with the bottom of the hole and provides a check on the weight indicator (weight indicators alone may give a false indication). A similar procedure should be used for testing inside casing or straddle testing in the open hole. The mark should be positioned so that test tools will be correctly located and the surface control head is conveniently accessible on the derrick floor.
The weight of the testing tool assembly should be recorded before running drill collars and drillpipe to ensure that the correct allowances are made when setting packers and for tool opening.
On wells where deviation is a problem, "hole drag" should be checked before setting packers or opening the tool.
When the bottom is reached, check the measurements to determine the amount of hole fill. Prior to running the test, make sure that the flare line is properly connected, secured, and free of obstructions.
While running in, the drillpipe should be checked for leaks by observing whether or not air is flowing from the pipe. Test string displacement should be closely monitored in a trip tank as the tools are run in.
158.Obtaining the test
If necessary, the annulus should be filled prior to opening the tool. A close watch on the annulus should be maintained when opening the tool. A sudden drop in fluid level indicates that the packer is not holding and an attempt to reset the packers should be made. A very slow loss of fluid is not serious since it is usually caused by loss of mud or filtrate to a fractured or porous zone above the packers. A constant watch should be maintained throughout the test and the mud level must be in sight at all times using the trip tank for filling the annulus.
In the event that sour gas is flowed to surface, the tool must be shut-in immediately.
Short duration, non-flowing, open-hole tests should not be permitted to exhaust gas or air to the
atmosphere within the derrick floor. In the event of an emergency, flow lines should go to the flare boom and sufficient chicksans should be connected to the control head to permit the pipe to be picked up with minimum delay to close the hydraulic tool. A steel cable is attached to the control head, clamped to each chicksan, and onto the floor manifold.
All electrical wiring must be in good condition. Drawwork engines should be at idle in order that hoisting power be available without delay.
Gas flow rates should be measured and recorded at least every 15 minutes. A recording chart should be used with an orifice well tester.
Obtain two samples of gas on every test. One sample is to be obtained shortly after the gas reaches the surface, and a second sample taken near the end of the flow period.
The initial puff and air blow during pre-flow and flow periods should fall into one of the following categories:
159.Weak - steady, slow stream of bubbles on surface of water pail.
160.Fair - steady stream of bubbles from four inches or less below water surface. 161.Good - steady blow up to 30cm below water surface.
162.Strong - steady blow to bottom of bucket, and is usually turned down to flare line. 163.Very Strong - steady blow that lifts water out of the bucket. (Normally diverted to flare
line.)
Always record the number of minutes for gas or fluid to reach the surface, and whether it was on pre-flow or final flow.
164.Pulling the tools
Any test where liquid hydrocarbons have flowed to the surface, or that is known or suspected to, contain liquid hydrocarbons, cannot be pulled at night unless the hydrocarbon is first reverse circulated out of the drillpipe.
If a small steady flare appears and does not die shortly after shutting in the tool, the drillstring may contain oil. Use plugs when tripping out.
When pulling a test, pay particular attention to hole filling procedures. Do not run the pump continuously. Stop every few stands to fill the hole. Ensure the mud level in the tanks is dropping proportionately to the amount of pipe pulled. Always use a trip tank when pulling a test. If a fairly long interval is tested, you should suspect a gassified mud column in the annulus. Extra care must be taken that the hole is properly filled.
Catch samples at the top, middle, and bottom of the recovered fluid column. Samples of recovered formation water must be sent to a laboratory for analysis and must be accompanied by a completed