METHOD AIDS CALCULATION OF PHPA DEPLETION RATES

L. Don Williamson
International Drilling Fluids Inc.
Houston

Kazem Javanmardi Ken Flodberg
Shell Offshore Inc.
New Orleans

A series of tests comparing partially hydrolyzed polyacrylamide (PHPA) concentration amounts has helped determine a new method for monitoring the depletion rate of the inhibitor in drilling fluids.

Being able to monitor actual excess inhibitor levels helps in the evaluation of drilling fluid performance and overall mud cost. Cost and performance relate to the rate at which the inhibitors are spent, regardless of the mechanism for formation control (e.g., chemical inhibition, physical encapsulation, or a combination of mechanisms).

The depletion rate of inhibitive agents in drilling fluids can, in many cases, present serious problems to a drilling operation. As the formation type varies with depth, the depletion rate varies; thus, the inhibitor level should be adjusted to correspond with the formation reactivity.

For the most part, the drilling industry uses qualitative methods to determine the inhibition level of a mud (e.g., determining the level of inhibition from a subjective analysis of the cuttings passing over the shaker screens). Many quantitative analysis methods fail to present correct values of excess inhibitor level, particularly for muds which depend on PHPA for inhibition.

Excess polymer can increase the mud cost and may cause operating inefficiencies.

An inhibitive index experiment was designed to further the understanding of PHPA depletion rates and to develop a method of quantitatively identifying these rates.

The project was designed to provide useful information regarding the performance of PHPA drilling fluids. The data were obtained through rock analysis in conjunction with hot roll dispersion assays conducted at specific depth intervals.

The data gathered during the drilling of a test well could be used on subsequent wells in the adjustment and maintenance of an optimum level of PHPA polymer in the drilling fluid. These data could also minimize any possible over treatment, thereby providing cost savings at high performance levels.

One of the main objectives of the test-well project was to determine the relationship between drilling fluid inhibition and the level of PHPA in the fluid; the PHPA level from the concentration sheets (material mass balance) was compared to that from chemical analysis. Another important objective was to establish the optimum economic level of PHPA required for peak drilling performance.

PROCEDURES

The analysis procedure called for three dispersion assays for each specified depth interval.

Assay No. 1 consisted of a solution of deionized water adjusted with sodium chloride to a salinity within 2,000 mg/l. of the salinity of the mud at the specific test interval.

A sufficient level of PHPA polymer was added to this solution to achieve greater than 90% recovery of formation material. Before the spudding of the well, tests on shale samples from an offset well indicated this PHPA level.

Assay No. 2 consisted of the drilling fluid sampled from the pit system for a given depth interval. The mud sample was diluted with a specific volume of saline solution matching the salinity of the mud sample.

This procedure reduced the mud rheology to a level so that the rheology would not affect the cuttings dispersion during rolling.

Assay No. 3 consisted of a solution of deionized water with the chloride level adjusted to within 2,000 mg/I. of the current fluid chloride level. This sample provided the maximum cuttings dissolution (or minimum inhibition level) should the effective PHPA level remain at or near zero.

Specific procedures were followed for solution preparation, cuttings preparation, and cuttings recovery techniques. Following recovery of shale samples and calculation of percent recovery, the index number was calculated (see equations below) and plotted against PHPA concentration numbers.

These numbers were also plotted against other variables such as pH and low-gravity solids level.

A = (Assay 2 -- Assay 3)/100

B = (Assay 1 -- Assay 3)/100

Inhibitive index = (A/B) x 10

The calculated index number represents the relative inhibitive level of the mud (affected by mud chemistry and polymer concentration) for the rock drilled.

The index number is based on hot roll dispersion test results.

The hot roll dispersion assay is a process of immersing a specific amount of sized (20, 40, and 60 mesh), prepared cuttings in a given solution, sealing the container, and oven rolling the mixture at 150 F. for 16 hr.

Following the rolling process, a series of sized screens extract the remaining cuttings from the fluid. The cuttings are cleaned and dried for a specific time interval and then weighed.

The calculation of the weight of formation material lost in the rolling process can indicate the dispersive tendencies of the particular cuttings sample in the given solution. This weight-loss mechanism, applied to three types of fluid from specific depth intervals, determined the drilling fluid inhibition index number on the test well.

This index number ranges from 0 to 10 units and is graphically represented against the PHPA concentration in the fluid as determined by both material mass balance and chemical-filtrate analysis. The index number indicates the relative inhibition level of the mud with reference to the formation drilled at a given sample depth.

SAMPLING

Because most of the testing occurred at the well site, it was necessary to have a suitable lab facility with complete testing equipment, including the following: a controlled temperature environment, hot roll oven, analytical balances, sample dryer (heat lamp), hot plates, glassware and reagents for PHPA chemical analysis, screens, and standard mud-analysis equipment including a 6-speed Fann rheometer.

A chemist from International Drilling Fluids Inc. set up a lab at Shell Offshore Inc.'s deepwater well location and trained the field personnel to run the inhibitive index tests.

The lab unit arrived on location 3 days after sampling had begun. The mud and cuttings samples were prepared according to the testing procedures while the lab was set up. Once the lab facility became operational, the back samples were analyzed.

As drilling progressed, samples of formation and mud were collected at 500-ft intervals. Approximately half of the formation samples were retained at the rig lab for index analysis and half were sent to IDF's analytical lab in Sandersville, Ga., for CEC and X-ray analysis.

The mud samples were split into three portions: one sample was retained at the rig for index analysis, one sample was sent to the analytical lab for filtrate analysis, and one sample was sent to Houston for particle-size analysis.

The information gathered during the course of the project was not used to adjust drilling-fluid properties on this well. Had abnormal treatment procedures been used relative to four previous wells drilled in the area, the data generated by this experiment may have misrepresented normal drilling conditions in the area.

The goal was to obtain information regarding the drilling fluid's performance for the rock drilled and to use this information to formulate muds containing an optimum polymer concentration for future projects.

Results from this experiment indicate the possible relationship between the material mass balance PHPA concentration and the PHPA concentration obtained from chemical filtrate analysis.

This relationship may provide a key to adjustment of the PHPA addition rate. The index number itself only indicates the level of inhibition produced by the mud at a given point.

Formation and mud sampling continued beyond a depth of 20,000 ft for a total of 26 data points. The testing procedures in the index project varied from very accurate to relatively high experimental error. All of the data generated off the well site are considered very accurate.

The hot roll dispersion analysis performed at the rig, however, has considerable test variability. It is extremely difficult to predict the exact degree of accuracy in this type of testing.

Several procedures reduced test variability, including dilution of the mud sample to reduce any viscosity effects on dispersion during hot rolling. Test error becomes less of a problem as the number of tests increases. The 26 test runs minimized the impact of test variability and provided a good representation of formation reactivity relative to the drilling fluid.

INHIBITIVE INDEX

Fig. 1 presents the primary correlation necessary to substantiate the inhibitive index curve. A fairly good correlation exists between rises in formation CEC and the index curve.

As formation reactivity rises, the mud relative inhibition level falls because the primary inhibitor is used more rapidly than it is supplied. Thus, the rate of inhibitor consumption exceeds the rate of addition.

The primary inhibitor in the test well drilling fluid was 30% active PHPA polymer. This compound adsorbs onto the surface of active particles, encapsulating them and reducing water intrusion into the clay structure.

This material is highly active. If there are not enough active cuttings or formation for reaction with the PHPA polymer, it can agglomerate on and blind the solids-control equipment screens. To maintain high flow rates and minimize mud loss across the screens, a number of operators run low levels of polymer in the mud and increase the concentration only as indicated by the cuttings condition.

One of the most active formation types drilled on the Gulf Coast is rock which contains high levels of montmorillonite clay. This clay has a very high surface charge density and consumes high levels of inhibitor when drilled.

Fig. 2 indicates the inhibitive index response to the changes in formation montmorillonite content encountered on this well. The response to the montmorillonite curve is much more dramatic than the CEC response and displays a very pronounced inverse relationship to the index curve.

In Fig. 2, Points 6, 9, 17, 21, and 24 display a nearly perfect response to changes in formation charge density. As the charge density increases, corresponding to an increase in montmorillonite day content, the inhibitive index falls. This indicates the reduced inhibitive level of the mud relative to the rock drilled.

Changes in the rock chemistry and variations in the type of rock affect the drilling fluid in several ways. The primary response of the drilling fluid to an increase in formation CEC is the depletion of the inhibitors in the fluid. In response to a lower level of inhibition, the cuttings and well bore begin to disperse, resulting in an increase in the low-gravity solids and methylene blue test level.

INDEX VARIATION

During drilling of the test well, the index varied from 1.5 to 8.0, with a corresponding variation in polymer depletion rate.

As the inhibitive index fell, an increase in the difference between the mass balance PHPA concentration and the filtrate analysis level occurred six times over the course of the well (Fig. 3).

The variation in the two concentration curves is the rate of consumption of PHPA polymer relative to the rate of addition indicated by the mass balance (concentration sheet value) PHPA level.

A graph of this difference in PHPA concentration level indicates the inverse relationship of the curves (Fig. 4). This relationship helps establish a means for controlling PHPA levels in polymer muds.

Effective control of a drilling fluid's inhibitive level allows optimization of the fluid with respect to the formation drilled. Proper adjustments of the inhibitors can lead to a more cost-effective drilling fluid.

The common approach has been to control the polymer or other inhibitor level at a concentration thought to be effective for the entire well.

This approach results in excessive concentrations of inhibitor while low reactivity formations are drilled and an unknown level while active rock is drilled.

The only method available to date for the determination of polymer concentration effectiveness has been the visual inspection of cuttings at the shaker. No current method can quantitatively determine polymer performance level.

This experiment provided a method believed to determine polymer consumption rates. The inhibitive index value shows the relationship between the mass balance concentration of PHPA and the concentration as determined by filtrate analysis.

If the level of polymer in a drilling fluid is above the level of consumption, the polymer may agglomerate on the shaker screens. This condition effectively blinds the screens, resulting in mud loss.

With an accurate method of determining PHPA consumption, a base level of polymer can be selected to minimize blinding while low-reactivity formations are drilled. As formation reactivity increases, the polymer concentration can be increased as necessary to satisfy the formation requirements.

Fig. 4 shows the inhibitive index response to the PHPA consumption rate. A plot of the two PHPA curves allows a prediction about the inhibitive index value. As the curve difference increases, an increase in addition rate of polymer should occur.

OPTIMUM CONCENTRATION

Another approach to correct for drops in inhibitive index levels is to maintain a preselected polymer concentration for the duration of the drilling project and to add supplemental inhibitor as required. This manner of drilling-fluid treatment is a more clinical approach to mud maintenance than traditional methods. This type of treatment should result in a high, flat profile on the inhibitive index curve rather than the peaks and valleys as shown in Fig. 5.

A sufficiently high level of inhibition reduces the dispersion of the well bore and the cuttings. This reduction in drill solids content reduces the volume of whole mud dilution required to maintain an appropriate level of low-gravity solids in the mud. The smaller dilution volume decreases the overall drilling-fluid cost on a project.

The dilution-volume curve is a direct inverse function of the inhibitive index curve (Fig. 5). As the inhibitive index rises, a subsequent fall in dilution volume is anticipated. This method of drilling fluid treatment may provide total system optimization for PHPA muds.

Because PHPA muds are typically treated in response to changes in cuttings integrity at the shaker, solids can build up rapidly before increased treatment levels can become effective.

Fig. 6 indicates the average shaker screen size, which was reduced after the drop in the index. This response is delayed somewhat compared to the drop in the relative inhibition level of the mud. The screen-size curve tracks the inhibitive index curve but is slightly shifted to the right, indicating a delayed response to solids loading of the drilling fluid.

The timing of changes in the PHPA addition rate is critical. If the rate of addition is increased without a corresponding increase in formation reactivity, the polymer will tend to blind solids-control equipment screens resulting in loss of mud and expensive chemicals.

The use of a PHPA concentration variation curve should allow proper timing for rate-of-addition changes, thereby minimizing loss of mud across screens because of blinding. The use of supplemental or complementing inhibitors in mud treatment may further reduce the potential for mud loss during adjustments in inhibition level.

Treatment with the appropriate supplemental inhibitor will only slightly affect the fluid's rheology yet may increase inhibition.

This process should be aided by the development of PHPA polymers that do not produce the viscosity increases normally seen from the use of concentrated PHPA.

CONCLUSIONS

This project included five main objectives:

The first objective was to define the relationship between drilling fluid inhibition and the level of PHPA in the drilling fluid as determined by both concentration sheet and filtrate analysis.
This objective was fulfilled during the course of the project and is probably the most valuable information obtained, as shown by Fig. 3 which clearly depicts the relationship between inhibition and PHPA level.
As the variation between the two PHPA-concentration numbers increases, the inhibition level of the mud relative to the formation drilled at that time decreases. This relationship may have an application on future wells as a guide in the PHPA treatment schedule.
The goal is to reduce the amplitude of the variation curve through a close monitoring of the PHPA level with both methods (concentration sheet and filtrate analysis).
As an increase in curve variation is noted, the polymer addition rate should be increased or the addition of a complementing supplemental inhibitor should be initiated.
The second objective was to establish an optimum PHPA level for peak drilling fluid performance based on rate of penetration, well bore stability, cuttings integrity, and other performance criteria.
There is no specific concentration level which will provide formation stability for the duration of a well; rather, the concentration level of PHPA or inhibitors in general must be adjusted dynamically as the formation reactivity changes.
Economical treatment of a drilling fluid implies that only the products necessary at a given depth should be added to the mud. This treatment can be accomplished through the use of the inhibitive index concept.
It may be unnecessary to use inhibitive index testing on subsequent wells but only to use the knowledge gained from this test well (i.e., curve variation between filtrate PHPA analysis number and mass balance concentration number).
The third objective of the well was to define a drilling fluid inhibition level at a specific well depth and to correlate this information with well bore caliper logs and bit performance data.
The caliper log correlation, however, was inconclusive because too few data points were available across the appropriate sections of the hole. Further study in this area should be conducted to define the relationship between hole size and the inhibitive index.
The fourth objective was to provide a full spectrum (index analysis, X-ray diffraction, and cation-exchange capacity) of formation analysis tied to well depths for the test well. The samples were taken at approximate 500-ft intervals from a depth of 9,100 ft to total depth.
Of particular interest is the formation montmorillonite content, which helped prove the validity of the inhibitive index number. Fig. 2 shows the increases in formation montmorillonite concentration corresponding to decreases in the inhibitive index value.
Because the inhibitive index seems to respond more definitively to the montmorillonite curve in Fig. 2 than to the CEC curve in Fig. 1, the value of CEC information alone is questionable.
The fifth objective of the experiment was to determine the effects of particle-size distribution in the discontinuous phase of the fluid on PHPA performance.
The data collected during this project, however, have provided little insight into this relationship. The median particle size was plotted against PHPA and index variables, but no particular relationship occurred.
Further studies are necessary to indicate a relationship between particle size and PHPA performance.
Also, the drilling fluid on this project was maintained in a relatively clean state for the duration of the well. There was little variation in particle-size distribution aside from what normally occurs with increases in density.
The results from this experiment may allow for PHPA system optimization on subsequent wells through the use of the PHPA variation curve. Others in the drilling industry should repeat this experiment in hopes of duplicating the data trends indicated on this test well.

The results of this experiment show that sufficient data exist to support the use of the PHPA variation curve in controlling the relative inhibition level of a PHPA drilling fluid. Two methods of treatment are currently under consideration.

One method involves maintaining approximately 1.5 lb/bbl PHPA (by filtrate analysis) in the drilling fluid and increasing this level only in response to upward movements in the PHPA variation curve.

The PHPA concentration would then be allowed to fall back to 1.5 lb/bbl as the curve falls.

A second method of treatment involves maintaining the PHPA level in the drilling fluid at approximately 2.0 lb/bbl according to the concentration sheet and adjusting for concentration variation with a supplemental inhibitor.

Several supplemental inhibitor agents are currently under study for use on future projects.