Site icon Oilfield beginner

INTRODUCTION TO FLOW TESTS

ishak

Tests on oil and gas wells are performed at various stages of drilling, completion and production. The test objectives at each stage range from simple identification of produced fluids and determination of reservoir deliverability to the characterization of complex reservoir features. Most well tests can be grouped either as productivity testing or as descriptive/reservoir testing.

• Productivity well tests are conducted to;

• Descriptive tests seek to;

Types of Tests

In this section we will deal with the most common of tests carried out and that is Clean Up then flow. It also covers the DST Test which is now only carried out on rare occasions.
When you talk about well testing only two things actually happen:
Drawdown – When you flow the well
Buildup – When you shut in and monitor the pressure
These two things are generally all that happens during a Well Test and it is the frequency with which they are carried out determines the type of Well Test.

Well clean up procedures

The purpose of cleaning a well as a preliminary flow operation to testing is to blow back into the well bore and to the surface extraneous fluids such as mud cake, mud filtrate, mechanically rock particles and most frequently, it is to unload well stimulation liquids-fluids such as spent acid or frac fluids which have been pumped into the formation.
The general characteristic of an “active well clean up drive”, or a clean-up flow in progress, is an increase in the well’s productivity, which results from the lowering of the saturation level near the well bore of the extraneous fluids, the corresponding increase in saturations and relative permeability of the formation fluids.
The initial phase of the clean-up sequence for a stimulated well may be characterized by low flowing wellhead pressures and recovery of large volumes of stimulation fluids.
As the clean up progresses, there is usually a rise in flowing pressure, a decrease in the rate of recovery of stimulation fluids and an increase in production of reservoir fluids.
The amount of pressure drawdown to be applied during the well clean up sequence should not exceed the level considered prudent for the largest test rate allowed for the well or approximately 30 per cent at the sand face due to danger of causing water coning or sand blasting into the well bore. This general recommendation does not apply to the initial stages when the liquid load in the tubing causes considerable hydrostatic back pressure at bottom hole. However, as the well’s productivity increases, the choke should be progressively adjusted to prevent excessive draw downs.


In the case of very low productivity wells, it may be necessary to flow them wide open in order to unload the liquids and also to adopt an off-and-on clean up procedure known as “stop cocking” in order to allow the well bore region to recover some of the formation pressure during the shut-in periods and use the higher initial productivity to achieve some degree of effective clean up action.
The well’s performance during clean up should be recorded with the same care and frequency as during testing operations in order to check on clean up progress and obtain preliminary information to assist in finalizing a testing program.
Once the choke has been set to a desirable opening, flowing tubing head pressures should be plotted versus log of flow time on a semi-log graph. Also, water and oil production should be tabulated, and the production rate regularly calculated, so that changing trends can be observed. Completion of clean-up will be marked by a stabilization of water production rate and no further increase of the well’s productivity.
There are no technical means of predicting the flow duration necessary to effectively
clean up a well. Only the observations and analysis of the flow characteristics during
the clean up period can give some measure of the clean up progress achieved.

The following are observations which may indicate nearing the end of the clean-up phase:

In general, wells in the high productivity range tend to clean up faster than those at the other end of the scale.

The well flow should initially be directed to a tank or overboard through the gas flare line. Gas well cleaning up can be continued through the flare as the gas volume increases. In the case of an oil well, the flow should be directed to the burner once it is apparent oil has reached surface.
The cleaning up operation should be carried out with great care, bearing in mind the possibility of serious damage to equipment by abrasion (sand, mud, perforating debris, etc. brought up with the well fluids). It is advisable to use the choke manifold near the wellhead and to bypass all testing equipment (heater & separator).
Under no circumstances is the well to be cleaned up through the separator. Avoid exposing the equipment for prolonged periods to any fluids containing sand (e.g. after fracturization), or H2S if the equipment is not designed specifically for H2S service.
Normally after the initial clean up period the well will be shut in to build up pressure back to reservoir pressure and then flow testing can be carried out.

Drill Stem Test

A set of drill stem tools is an array of downhole hardware used for the temporary completion of a well. They are run as a means of providing a safe and efficient method of controlling a formation during the gathering of essential reservoir data in the exploration, appraisal and even development phase of a well, or to perform essential pre-conditioning or treatment services prior to permanent completion of the
well.
Two types of Drill Stem Tests are carried out they are:

Open Hole Drill Stem Testing

If hydrocarbons are detected in either cores or cuttings during drilling or indicated by the logs, an open hole DST provides a rapid, economical means to quickly assess the potential of the formation. However, the technique requires the hole to be in very good condition and highly consolidated as the packer elements actually seal on the rock face. The open hole sections also limit the application of pressure on the annulus, therefore special strings are designed which are operated by pipe reciprocation and/or rotation. The Multiflow Evaluator System (MFE) is a self-contained open hole drill stem test string.
If drilling is not halted to allow testing when a potential hydrocarbon bearing zone is encountered, and alternative test method is to wait until the well is drilled to total depth and then use straddle packers to isolate the zone of interest.
Open hole drill stem tests gather important early information, but reservoir testing requires more data over a longer period. The extent of reservoir investigated increases with test duration. A key factor governing the duration of an open hole test is well bore stability. At some point the well may cave in on top of the packer and the string may get permanently stuck downhole, calling for an expensive sidetrack.
These hazards of well bore stability have been eliminated by testing after the casing has been set and, in many sectors, particularly offshore, cased hole testing has replaced traditional open hole drill stem testing.

Cased Hole Drill Stem Testing

As offshore drilling increased, floating rigs became common, increasing the potential for vessel heave to accidentally cycle traditional weight set tools and even un-set the packer. In addition, deeper more deviated wells make reciprocal tools more difficult to operate and control and thus jeopardize the safety of the operation. A pressure-controlled system was designed specifically for these applications, eliminating the need for pipe manipulation after the packer has been set, and eventually becoming
the new standard in drill stem test operations.

DST Tools

The basic tools on a DST String are as follows:
Paker – This provides a seal and isolates Hydrostatic Pressure from Formation Pressure much the same as for permanent completions.
Tester Valve – A test valve, run above the packer, isolates Cushion Pressure from Hydrostatic Pressure while running in the hole. It also helps reduce the effects of well bore storage which is an important element of interpretation. After the packer is set and the tester valve opened, flow to surface occurs.
Reverse Circulation Valve – A reverse circulation valve provides a means of removing produced fluids before pulling out of the hole. For redundancy, two reversing valves with different operating systems are normally run. In addition, reversing valves are used to spot cushion and acid treatments.
Slip Joint – A slip joint is an expansion/contraction compensation tool. It accommodates any changes in string length caused be temperature and pressure during the DST. The tool is hydraulically balanced and insensitive to applied tubing pressures. Slip joints have a stroke of approx. 5 feet, the total number of slip joints depends on well conditions.
Hydraulic Jars – A hydraulic jar provides the means of transmitting an upwards shock to the tool string in the event that the packer and lower assembly become stuck. The tool has a time regulated action as transferring rapid movement in a long string is not a simple matter. An upward pull activates a regulated oil flow until the hammer section is released thus giving a rapid upward movement and generating
the relevant shock.
Safety Joint – A safety joint is actuated only if a jar cannot pull stuck tools loose. By manipulating the tool string (usually by a combination of reciprocation and rotation), the safety joint, which is basically two housings connected by a course thread, can be unscrewed and the upper part of the string removed from the well.
Gauge Carrier – When run with a test string, both mechanical and electronic gauges must be placed in a carrier for support and protection. Carriers can either be of the above or below packer type.
Many more tools can be added to a DST string, depending on the requirements of the client.

Exit mobile version