DRILLING FLUID PROPERTIES

To achieve the listed objectives, either in total or in part, the drilling fluid is tested and continuously modified by dilution and chemical addition. Geological changes down hole require versatility in blending.

To achieve the optimum performance from any drilling fluid system it must be constantly modified and rebuilt. The testing of drilling fluids is extremely varied and it is becoming increasingly complex. The objective is, however, always the same: To monitor the system to provide the optimum drilling environment with the maximum formation protection.

This monitoring of the mud is done on an almost continuous basis, principally by the operation of chemical testing. Tests and testing procedures vary enormously depending upon the specific requirements at the time and the type of drilling fluid in use.

A drilling fluid engineer will use the range of tests on which to base a recommended treatment.

He will develop a “feel” for the chemical interactions that are taking place and react accordingly.

Prior to discussing the range of systems in use today, and some of the systems no longer in use, it is useful to cover the basic drilling fluid properties.

A wide battery of tests is available to the engineer. Testing can take considerable time and results are of varying importance. The introduction of new chemicals or the running of new systems naturally requires additional testing. As it is not possible to effectively report on all the tests available in this context, it is beneficial to cover the standard tests that are carried out on the bulk of water-based systems.

It is recommended that the Wellsite Geologist becomes familiar with the Daily Mud Engineering Report and maintains a close liaison with the Drilling Fluid Engineer.

The Drilling Fluid Engineer is often aware of changes to the mud that are being driven by formation chemistry that the Wellsite Geologist may not see. The dispersing nature of some formations often will not be seen by the Wellsite Geologist in their samples, as the material may have dispersed into the drilling fluid.

The principal testing on most water-based muds and reported in the Daily Mud Engineering Report consists of the following:

5.4.1 Sample

The drilling fluid is generally sampled from either the “active” mud pit (the pit on line) or the Flowline. The report form will indicate from where the sample was collected. A pit sample should reflect what is going down the hole, after chemical treatment and solids removal. It should be accurate to the well program in terms of its chemistry. Flow Line samples are extremely useful to compare with the Pit sample. This comparison will indicate the effects down-hole exposure is having upon the mud. Discuss the variance with the mud engineer to extract formation chemistry information. The rate of mud disintegration and the chemical changes being experienced can indicate the type and nature of formation being drilled.

5.4.2 Time Sample Taken

Noting the time the sample was collected will enable the engineer to compare the rate of chemical change from the time the samples were taken. Ideally a full test should be taken on a Pit Sample and a further test taken at the Flow Line once a full circulation has completed. Note the Circulation Times from the form and the actual test times to determine where the sample was at the time of testing.

5.4.3 Flowline Temperature

Monitoring Flowline temperature ensures additives are not expected to perform outside their normal operating range. Do not always believe the quoted effective bottom hole temperature limits of many products. Chemicals will generally degrade rapidly as temperatures increase to

their published maximums. Many, including some of the exotic polymers, will catastrophically fail prior to temperatures reaching their operating limits. Others will produce unacceptable effects, including the generation of CO2. These can confuse the Wellsite Geologist if he is unaware of the limitations of the system. The bulk of drilling fluid additives are effective up to 120°C, with very few capable of withstanding drilling conditions at 150°C. Discussions with the mud engineer on the temperature regime of his chemicals will help identify formation versus additives induced changes.

5.4.4 Depth

The depth at which the sample is collected and tested is recorded. The Wellsite Geologist should compare formation tops and geological changes with changes that may have been registered in the fluid chemistry at the same depths. Alert the drilling fluid engineer to anticipated changes in formation and he will be able to confirm changes also seen in the fluid.

5.4.5 Weight

The density reading in conjunction with hole condition is a valuable tool for estimating the down-hole pressure regime. A density increase will generally improve down-hole cleaning and may result in Wellsite Geologist seeing a change in the ratio of sand/clay cuttings returning to surface or in the blend of formation returning. These changes may not be directly related to formation changes but are associated with the changed hole-cleaning environment. Under-balanced drilling will often result in cavings entering the wellbore from further up the hole further confusing sample interpretation.

5.4.6 Funnel Viscosity

The Marsh Funnel was the first, and is still the simplest, of mud testing tools. The measurement will enable the mud engineer or derrickman to get a quick understanding of changes in overall system viscosity. The Marsh Funnel Viscosity will not tell from what source the viscosity changes are occurring. PHPA and high polymer muds typically run much higher viscosity than traditional systems. Funnel viscosities of 40 to 55 sec/qt are regarded as normal. Water has a viscosity of 32 sec/qt.

5.4.7 Plastic Viscosity and Yield Point

Plastic Viscosity and Yield Point are measured to determine the flow properties of the fluid at known shear rates. The determination of Plastic Viscosity and Yield Point are derived from the Bingham Model and indicate the nature of the viscosity in the fluid. Low end Shear Rates are now also routinely tested and included on the drilling fluid form to evaluate the performance of drilling fluids in extended reach and horizontal wells. At its simplest Plastic Viscosity is a measurement of the solids content of the drilling fluid and the Yield Point is a measurement of the electrochemical charging of the mud. Drilling fluids that have high concentrations of solids will have high PV’s and modern polymer specific muds, which have viscosity generated from polymers instead of clays, have low PV’s and high YP’s. The ratio of the two is important and should be taken into account when evaluating hole cleaning and particle suspension.

The trend is to run the Yield Point much higher today than in previous times. Horizontal and extended drilling have demonstrated that very high low end rheologies are necessary to clean these wells and prevent the buildup of cuttings in the hole.

5.4.8 Gel Strengths

The Gel Strength is essentially a measurement of the thrixothropic nature of the mud, ie how quickly the fluid will produce gels and thicken once circulation is broken and to what extend this will continue. Readings are taken from the Fann Rheometer at 10 second and 10 minute durations and the degrees of deflection recorded. Ideally a fluid that produces a very quick gelling action is sought to stop cuttings settling in the hole once circulation is stopped. A high gel will produce a fluid that becomes too thick while out of the hole for extended periods, normally while logging or tripping. 10 second gel values of between 5 and 15 are acceptable, while 10 minute gels as high as 40 will be obtained and are not a cause for concern. A mud with a medium to low 10 sec gel, and a low 10 min gel, is described as having flat gels, while high 10 minute gels indicate the mud continues to thicken and is said to be progressive in nature.

5.4.9 Filtrate

Of special significance to the Wellsite Geologist is the rate at which drilling fluid is lost to the formation. The API fluid loss testing procedure is conducted to ascertain the nature and type of filter cake build up and the rate of filtrate loss across a membrane.

It is essential to obtain a satisfactory fluid loss value and the deposition of a thin, impermeable filter cake across the wellbore.

Two types of filtration are present; dynamic filtration which occurs when the mud is circulating and static filtration when the fluid is at rest.

Dynamic filtration testing is usually conducted in town to test the nature of the losses while circulating. These are generally significantly higher than static test results. To control the amount of filtrate lost to a formation, dynamic filtration must be controlled and to prevent disposition of thick filter cakes, static filtration must be controlled.

Loss of fluid (usually water and soluble chemicals) from the mud into the formation only occurs when the permeability is such that it will allow the passage of fluid between the pore openings. If the openings are large enough, the first effect is a mud spurt that enters these openings at the face of the well bore. Then, as additional fluid is lost, a build up of the mud solids (wall cake) is formed on the wall face.

There are a number of problems that can arise in drilling and completion operations due to muds with faulty filtration characteristics. These include:

1. Formation evaluation problems from excessive filtrate invasion and thick filter cakes.

2. Excessive formation damage from mud filtrate.

When large volumes of filtrate enter a formation, the formation fluids may be flushed from the zone around the wellbore to the extent that logging tools give erroneous results. Formation test tools may also recover only filtrate, making it difficult to determine the true fluid content of a formation. If there are clays in a formation, water filtrate may cause the clay particles to swell or disperse and thereby reduce the formation permeability.

Factors Affecting Filtration are:

Time - Filtrate volume increases in direct proportion to the square root of time.

Pressure - If the filtration medium were constant, the amount of filtration would vary as the square root of pressure. In the case of mud filter cake, this does not hold true

because the cake is subject to compressibility and continued deposition of material into the cake causes changes in porosity and permeability.

Cake Permeability on Fluid Loss is primarily influenced by temperature and the state of deflocculation of the system. It has been recognised that there is a correlation between high pressure-high temperature filtration properties and wellbore problems. Problems of primary concern are production zone damage (attributed to water blocking and the effect of mud filtration on shale or clay within the producing zone).

Water loss should not be considered as an absolute value, but as a guide or criterion to the filtration properties of the mud in the hole. Because of the many variables influencing the filtration properties of drilling mud in a well, it is most difficult to accurately predict fluid loss to the formation from the simple API filtration test.

As the hole is drilled deeper, it is necessary to adjust the fluid loss of the mud to assist in penetrating the new formations encountered. Consequently, it is not uncommon to drill a surface hole with a mud having a fluid loss of 20 cc. Values in the order of 4 to 8 are usually programmed for final hole intervals.

5.4.10 API HPHT Filtrate

The API HPHT test is designed to reflect the actual drilling conditions that are being encountered down-hole. A testing regime of 300°F and a pressure differential of 500 psi is the standard set-up; however, the test is often varied to reflect the particular well being drilled. Target HPHT losses of 20 to 25 cc’s are generally achieved.

5.4.11 Cake Thickness

The cake thickness is measured in 32^nd‘s of an inch and will provide valuable information to the mud engineer on the nature of the filter cake. Investigation of the cake will enable the engineer to test the strength of the cake in its condition. Correct filter cake makeup is essential in the avoidance of differential sticking.

5.4.12 Solids Content

Solids are reported as a percentage of the total drilling fluid and can be calculated by either a mass balance or the result tested with a Solids Retort Test Kit. A known volume of mud has the water driven from it and this is then distilled. The results of the retort are included into a solids analysis calculation and the resulting solids fraction further broken down into high and low gravity solids by calculation. The volume of salt is included in the calculation. The use of high volume linear motion shakers, centrifuges and low weight drilling fluids, have resulted in muds being run (where geologically possible) with the solids content typically in the 4% to 6% range.

5.4.13 Sand Content

Sand will have an abrasive effect upon drilling steels and results in excessive pump damage.

Values in the order of 0.25% are generally considered to be maxima. This value will be exceeded occasionally at the time of pay zone drilling or during intervals of rapid drilling in sandy formations.

5.4.14 Methylene Blue Capacity

The testing of the Methylene Blue Content will enable the mud engineer to determine the Cation Exchange Capacity of the mud and hence the clay content. Clays have a detrimental effect upon most drilling fluids and often effect rheology directly. The dispersion into the drilling fluid of the clays is lost sample to Wellsite Geologist. This formation is lost in the fluid phase of the drilling fluid and is eventually dumped in the dilution volume. Changes (particularly increases) in this value should be noted to ensure that the Wellsite Geologist is aware of its volume. CEC values of 20 to 25 are considered to be maxima in low solids drilling fluid systems.

5.4.15 pH

A battery of alkalinity testing is performed. Many chemicals operate within narrow pH bands and many are destroyed outside these fine ranges. The pH will affect performance and stability of many chemicals. Modern drilling fluids are generally run with low pH values by traditional standards. PHPA (Partially Hydrolysed Polyacrylamide), a powerful and common shale encapsulator, is extremely sensitive to increases in pH above 9.5 and a value of 10.0 will totally destroy the polymer. A low pH will lead to increases in steel corrosion. The Wellsite Geologist should be aware that corrosion additives may be added to the fluid that may be seen in their samples or will appear in subsequent laboratory testing. All corrosion additives (and other occasional additives) do not always appear on the drilling fluid report form.

5.4.16 Alkalinity (Pm Pf Mf)

Alkalinity testing is conducted on the drilling fluid in addition to straight pH testing. While the drilling fluid may have sufficient alkalinity the hydroxyl blend may not be in acceptable ratios.

Interpretation of results will alert the Mud Engineer to potential carbonate and bicarbonate contamination. Contamination can be the result of drilling soft cement, incorrect chemical additions or formation contamination. The Pf/Mf ratio should be closely monitored. As carbonate contamination is experienced the Mf value will increase, possibly up to 5 times the Pf in extreme cases. Alkalinity results should be evaluated in conjunction with the 10 minute gel, which will also indicate progressive gels in carbonate/bicarbonate environments.

5.4.17 Chloride

The chloride test is very significant in areas where salt can contaminate the drilling fluid. The salt may come from make up water, salt stringers or from salt water flows. Many drilling fluids being built in Australia use sea water in their make up. KCl is added in 90% of the wells drilled in the country to control swelling shales with its additional chloride burden. Sea water muds will typically run with chloride levels of 25k to 30k. Additions of KCl are gradually being reduced to ensure that the drilling fluid conforms to environmental needs. Chloride is an extremely aggressive ion and while the bulk of chemical additives now in use are salt tolerant, almost all will suffer a loss of performance to one degree or another as the chloride concentration increases.

5.4.18 Total Hardness

Water containing large amounts of dissolved calcium and magnesium salts is referred to as hard water. Many wells are drilled with hard water that is often pre-treated by the engineer before using. Drilling clays have low yields when mixed in hard waters. The harder the water the more bentonite that is required to make a satisfactory mud. Calcium can be picked up when drilling

cement or sections of limey shale. Drilling anhydrite will also result in eventual contamination of the drilling fluid system. Many chemical additives are hardness sensitive. PHPA muds are destroyed in the presence of calcium and calcium levels should never exceed 2000 ppm.

Extensive calcium contamination will result in abnormally high water loss and high gels.

5.4.19 Additional Testing

Drilling Fluid Report Forms will contain a large range of further test results and analyses depending upon the type of system being run. Look for the additions and, as the engineer who has generated the report is on the rig, discuss with him the direct implication chemical changes to the system will have on cuttings samples.