Full Operation Sequences
In the selection of drilling and completion fluids and procedures basic return permeabilities are routinely used. A basic test involves a permeability measurement followed by test fluid application and a final "return" permeability.
As well as performing basic return permeability tests Corex has had a great deal of experience in interpreting the data produced, which has led to the development of more pertinent tests.
Corex return permeability tests are conducted at reservoir conditions. There is a permeability base case and a return permeability but the Corex test involves a full simulation of all drilling/clean-up/completion operations and a simulated drawdown or return to production.
To clearly identify favourable non-damaging fluid candidates, remedial treatments and / or incorporate mechanisms or design operations to improve results for field use the permeability results, cryogenic SEM analysis and dry SEM analysis are required. If the fluid/fluids applications are considered based solely on permeability results then this may carry an associated risk because of fines migration and / or other flow reducing barriers. If drilling and/ or completion options are considered for any one sample type based on performing only single SEM analysis then this may carry an associated risk. However, if both dry and cryogenic SEM analysis is performed there would be less associated risk. Engineers would be able to customise the design of the fluid(s) and / or design mechanisms for successful field deployment based on knowing the full scope of damage mechanisms (nature and distribution). Therefore, Corex (UK) Ltd recommends both dry and cryogenic SEM to provide a complete evaluation of all possible fluid and solid damaging mechanisms.
In essence, to clearly identify favourable non-damaging fluid candidates, remedial treatments and / or incorporate mechanisms or design operations to improve results for field use the permeability results, cryogenic SEM analysis, dry SEM analysis, thin section analysis and XRD are required.
Below are related papers published by Corex that may be of further interest.
Drilling Fluids Screening
Corex offers a number of Drilling Fluid Screening Tests.
Drilling Mud Evaluation
For many years laboratory flood tests have been used to pre-screen various introduced wellbore fluids such as drilling muds and completion fluids. In order to fully interpret the results of such flood tests Corex continues research and development of recognised geological techniques which have a particular relevance to flood test interpretation.
Permeability versus throughput and fluid loss versus time measured at reservoir conditions are produced as standard. Using these results and integrating geological techniques such as SEM, Cryogenic SEM, Thin section, X-ray mapping and cathodoluminescence, it is possible to determine the causes of damage and potential solutions to formation damage problems. Combining permeability/fluid loss results with all of these techniques greatly enhances the value of reservoir conditions core flood tests.
X-ray elemental mapping can be used in conjunction with advanced core flood tests to predict and avoid formation damage problems. This particular example above shows how the technique can be used to identify elements from a backscattered SEM image (top left quadrant). A polished section perpendicular to the wellbore end face has been prepared and the examples shown identify the selected elements at the wellbore end of the sample and in the mud cake. The mud cake contains dolomite (calcium and magnesium) as the main weighting agent but considerable amounts of barium were also detected. The barium is thought to represent barite contamination from mud mixing tanks - this mud was a "live" or used mud sampled at wellsite. The mud solids do not extend deeper than the first pore throat into the sample.
Drilling Mud Filtrate Loss
The diagram illustrates a single pore showing coalescence of mud filtrate brine droplets and the development of a water in oil micro-emulsion due to mud filtrate loss into an oil leg Formation brine droplets are visible on a sand grain.
A high magnification view of the film of retained filtrate coating grains and draping across pore openings
Brine retained within pore lining and pore-filling native clays
A remnant pill cake attachment composed of sludge. Brine, oil and blocky fragments are observed within the sludge.
Rearranged chlorite plates compared to before test and dispersed kaolinite plates.
Polymer observed coating the wellbore face. Blowholes are common throughout sample
Core Flood Tests/Completions/Workover fluids assessment
Corex offers the following Completions services:
Core Flood Tests
This view shows the resulting residual formation brine saturation (bubbles adhering to the framework grains) after crude oil is flushed through a brine saturated plug. The plug is mainly oil wet but see the view right.
This view shows that the formation brine droplets wet the framework sand grains at their point of contact; however the crude oil wets the grains between each of the droplets. (Oil appears as the cracked regions).
Completion Fluid Loss
This view of a pore centre shows the precipitation of KCl crystals, when formation brine mixed with KCl completion brine in an oil leg, forming salt bridges which lock the oil droplets and prevent oil production.
A workover is any operation on an existing well, be it an oil, gas or injection well, which materially alters the physical condition of the well. There are many different types of workover including: scale treatment by injection, wax cleanout, recompletion, acid stimulation, fracture stimulation, water shut-off, gravel packing and reperforations. Often to carry out this work the well must be killed which means that the selection of the kill pill fluid is critical.
A kill pill requires that a fluid with a greater hydrostatic head than the reservoir pressure be placed in the well. Since the well will have been previously completed to produce at peak efficiency there will be a tendency for the workover fluid to leak into the formation. A good workover fluid is clean and devoid of any solids. A poor fluid will not only cause a potential well control problem but could also damage any perforations or the formation by plugging with insoluble solids. Therefore any chemical used must be able to flow back on finishing the workover when the well is brought back onto production or it must be destroyed by flow to oil or treatment with acid or water. Some typical workover kill pills are given below:
Kill Pill Solids
|Brine||Sized Salt||Under-saturated Brine|
|Brine||Calcium Carbonate||Hydrochloric Acid|
|Brine||Oil Soluble Resin||Diesel or Xylene|
|Brine||Fine Grained Cellulose||Sodium Hypochlorite|
|Brine||H.E.C. and X.C. Polymer||Hydrochloric Acid|
There are three critical things that must be tested for in a kill pill:
- Does the "filtrate" from the workover fluid and the fluid the kill pill is mixed with damage the formation?
- Will the kill pill prevent losses?
- What is more important in terms of well productivity, will it come out again?
The Cryogenic Scanning Electron Microscopy photo shows kill pill polymer (the dark areas) blocking pores which is preventing flow to oil. The polymer had invaded the plug and had not been broken fully by the application of hydrochloric acid.
Below is a related paper published by Corex that may be of further interest.