New downhole fluids further improve recovery

Completion fluid substitute

William Furlow
Technology Editor

MI L.L.C. completion fluids facility in Mongstaad, Norway. These calcium chloride pills are waiting to be mixed into part of a calcium brine in this plant.

Enhanced recovery and reduced rig time are fueling innovation in all aspects of exploration and production. The magic combination of these two factors can mean the difference between a profitable well and a shut-in.

The choice of drill-in fluids and completion fluids can dramatically affect production rates. Especially in the early stages of a well, high production rates are a top priority. If early production is high, it can help an operator pay off his well faster and realize profits sooner. In addition, a formation that is clean and undamaged will produce more over the life of the well.

Choosing a fluid

According to Schlumberger, reservoir properties and the completion design are the primary considerations that go into choosing a completion fluid. In a flow chart designed by the company, reservoir properties and the completion design are used as inputs in an inflow simulation, which is an optional but preferred step prior to making the initial fluids selection.

Offset information and likely damage mechanisms are also factors to consider in making an initial completion fluids selection. A short list of fluids can be gleaned from the initial fluids list. The operator then considers the added factors of drilling and logging requirements. Environmental considerations also play a role in this selection.

From the short list, a preferred fluid or fluids is selected and tested on cores in the lab. The goal here is to find a fluid that optimizes filter cake and fluid removal. Additives may then be programmed to enhance these properties. The last stage of design, execute and evaluate, the evaluation requires the constant improvement of the fluid, either through economics or performance.

In cased and perforated wells, completion fluids are circulated in the wellbore after a well is drilled to TD. The well is drilled down through the production zone with a solids laden fluid (mud)and then displaced to a clear brine completion fluid. In open hole and horizontal completions, once the drilling program reaches the production zone, the mud is circulated out in favor of a drill-in fluid, said Bill Foxenberg of MI. In this pay zone, the priority is to avoid formation damage and prevent loss of productivity. Drill-in fluids seal off almost immediately. They are formulated for very low leak-off, providing a removable filter cake with very little invasion into the formation.

Once TD is reached, and the last casing string is cemented in place, the well may be perforated through the production zone. In many cases, a sand control device, such as a gravel pack is pumped into the formation. A clear, solids-free fluid is used to transport this gravel.

Completion fluids are typically heavy brines capable of reaching the weights of solids laden muds without the addition of insoluble solids. This density is needed to control pressure downhole. It is important that these fluids are solids free so that they will not block or damage the formation. Once the gravel pack is in place, the fluids and any filter cake lain down for post-gravel pack fluid loss control need to be removed so the formation fluid can flow.

The key factors for completion fluids are the fact that they are solids free and dense enough to contain the formation pressure. These fluids would not work as drilling fluids because they aren't able to seal the formation, or transport out the drill cuttings. Under drilling conditions, specialty brines, called drill-in fluids, are used to drill and then only through the production zone where the formation must be protected.

"All the beneficial properties of the drilling fluids must be inherent in the drill-in fluids," Foxenberg said. In addition, it must be non-damaging to the formation and have a removable filter cake. These are two of the characteristics that distinguish drill-in fluids from drilling muds.

Completion fluids are solids-free solutions that can reach weights of 8.4-20 lb/gal. There are only a few salt systems that can offer a high enough solubility to reach the required densities without the use of solids.

"Most everybody in the completion fluids business carries these types of salt solutions," Foxenberg said. These fluids include everything from simple salts such as sodium chloride and potassium chloride to exotics such as zinc bromide and cesium formate. These exotic fluids can reach weights as high as 20 lb/gal based solely on the solubility of the salts. While the exotics offer heavy weights without solids, they can not be discharged into the sea. These fluids must be recovered and every bbl accounted for, according to Foxenberg. The lower density completion fluids, up through calcium bromide, can be discharged in most offshore environments with no environmental impact. Recycling of completion fluids, as with drilling fluids, is common. The initial investment in these fluids is very high, so recycling is seen as an essential cost saving measure. Minimal losses are expected into the formation, but recovered fluids can be chemically treated, filtered, and recycled.

Other functions

In addition to offering completion and drill-in fluids, MI and others in the business perform services and provide additives that complement the performance of their products. Foxenberg said these services and additives are geared toward preventing formation damage and loss of fluids to the formation. Fluid loss control additives are added to the brines to make the fluids more compatible with the formation in case they are lost to the formation. Surfactants also may be added to help in the recovery of the fluids and prevent emulsions from forming. Other additives are effective in preventing precipitation and scaling in the formation water. Fluid loss pills also may be added to the brines to increase their viscosity and reduce their invasion into the formation. Special displacement chemicals and displacement designs are engineered to ensure a clean wellbore after displacing the drilling mud to minimize contamination of the fluid and damage to the formation.

Services provided during completion include filtration and engineering services. The brines being used have to be of the proper weight, be free of solids, and used properly. MI and most other completion fluid companies offer these services worldwide. These fluids require specific engineering programs to predict downhole densities and the behavior of the fluids in the well.

MI and others are involved in evaluating the formation in order to select the proper brine and formulate the proper brine through the use of additives. It is important, for example to design the completion fluid to be compatible with the oil in a formation to avoid the formation of an emulsion.

Programs such as the displacement procedure are critical to the successful completion operation and must be engineered for the specific wellbore configuration and environmental conditions. In the displacement process, the mud is displaced from the wellbore and replaced by the completion fluid. Software is used to calculate circulating pressures, pressure differentials along liner tops and open or squeezed perforations. This engineering is essential to a proper displacement that will leave a clean wellbore and clean fluids.

Drill-in options

Schlumberger offers a water-based reservoir drilling and completing fluid called Stardrill which contains the additives Dualflo and Starcarb. Dualflo is a naturally-sourced polymer that provides tight fluid loss control and extension of low shear rate viscosity in all brine types. Starcarb is a specifically sized calcium carbonate that provides spurt loss control and favorable bridging characteristics.

Formulated at 10-80 lb/bbl, Starcarb avoids problems that may result from high solids loading in the fluid. The brine phase is used to generate the remaining fluid density needed. Different brines are used for different weights. Different brines will require different polymeric additives package used, according to Schlumberger.

In horizontal wells drilled through highly unconsolidated formations, controlled flow rates are used to avoid hole erosion. While controlled flow rates protect from excessive erosion, they also can promote the development of cuttings beds. The low sheer rate viscosity of Stardrill means it aids hole cleaning even at these low rates.

Schlumberger custom designs its drill-in fluids, as do other companies, taking into account the average pore throat size, expected formation permeability, and the type and quantity of clays or mobilizable fines particles. In the permeability plugging test (PPT) the fluid's bridging capability is fine-tuned by filtration tests against a ceramic dish which has pore openings near that expected in the hydrocarbon bearing formation. The dynamic filtration test indicates the likelihood of sticking problems by testing how the fluid will perform in terms of filter-cake thickness.

The desired properties of a good filter cake are conflicting, according to Schlumberger. The cake should remain intact and leak-proof during completion operations, such as running in completion strings or sand screens and gravel packing, yet it should be easily removable when the well is completed to avoid clean up operations and impaired production.

Baker Hughes Inteq bases its drill-in fluid designs on the ability to form a thin, less than 1 mm, filter cake that can be easily removed by minimal production pressure. This is achieved through the selection of specific polymers and an appropriate bridging agent, according to Tom Jones, Product Manager for Drill-in and Completion Fluids. Jones said the development of a quality filter cake depends mainly on the particle distribution of the bridging agent. Inteq formulates its Perflow system so that at least 5%, by volume, of the bridging agent is present in the drill-in fluid. The particles of the bridging agent must be at least one-third the size of the aggregate pore throat diameter of the reservoir sand. He said this ratio, coupled with the proper polymer ratio, guarantees good bridging with low spurt losses and a thin filter cake that can be displaced by formation pressures as low as 8 psi. Prior to field usage, Inteq's drill-in fluid must pass this 8 psi lift-off requirement in the laboratory using a sandpack permeameter. If an operator is planning remedial breaker/acid clean-up and the chemicals do not contact all the reservoir surface, the filter cake will be removed by the resulting production.

It is important during displacement that the drill-in fluid be completely removed and replaced with a completion fluid. This ensures that the gravel pack or pre-pack screens will not be plugged when the well is put on line. It is also paramount that a positive hydrostatic pressure be directed on the filter cake so that it will remain in place during the completion process. Otherwise, the cake will come off and loss of circulation may occur.

Because the remaining filter cake is usually less than 1 mm thick when it is produced off the well bore face, it will not plug the gravel or production assembly. A well designed drill-in fluid should have a rapid shut-off, very little spurt loss, followed by a rapidly-established plateau in the level of filtrate loss. Using formation damage testing equipment, Schlumberger can test actual formation cores to obtain lab data for the formulation of drill-in fluids.

Damage testing

Formation damage testing, as explained by Schlumberger, uses a field core or outcrop core to evaluate the reservoir drilling fluid and minimize the damage potential and also investigate the proposed wash fluid efficacy, if one is programmed. This testing involved laying down a filter cake and applying the proposed breaker fluid.

Breakers include enzymes, acids, non-acid breakers, encapsulated breakers, oxidizers such as bleach, or combinations of these. The effectiveness of these wash fluids can be evaluated by how effective they are in removing the filter cake and by testing the core permeability after treatment.

New drill-in fluids uses

At Baroid and other companies, drill-in fluids are being used for more than drilling through the pay zones of wells. Larry Leggett, Vice-President of Completion Fluid Services for Baroid, said these solids-free fluids are being used as an alternative to drilling muds for overcoming shallow gas zones in deepwater fields of the Gulf of Mexico.

Leggett said Baroid is working with Vastar on the Mirage field in the Mississippi Canyon area. The field is in 3,960 ft of water and has a shallow gas zone. This portion of the well is being drilled riserless, using large volumes of a specially formulated drill-in fluid. What is unique about this project is that the fluids will be stored in the legs of the Ocean Victory, rather than being brought out on a barge.

It is possible to store 26,000 bbl of this dense fluid in the ballast tanks of the semisubmersible, because the fluid contains no solids that would clog pumps or make it difficult to remove from the legs. This base fluid will be mixed with 5 lb/bbl of calcium carbonate, as it is pumped from the legs at 20 bbl/min. This additive will allow the fluid to achieve a high enough weight to contain the gas and allow the first string of casing to be set. Once this string is cemented in place, the project will switch over to a conventional drilling fluid and a riser system. The use of this drill-in fluid for shallow gas containment is made possible by N-vis HB suspension agent, which will suspend the calcium carbonate in the fluid. If a conventional mud were used for this project, it would require the addition of large amounts of clays and other solids to reach a weight high enough to hold back the gas.

It would not be possible to add such a high volume of solids at the required pumping rates of the well, Leggett said. The N-vs HS uses a heavier brine as a base fluid so it doesn't require that such a volume of solids be added.

The returns from this riserless program will be released at the seafloor, so Leggett said the rig has to carry all the fluids needed to complete the program, since none will return to the rig for cleaning and reuse.

Mudzymes

One of the main reasons drill-in fluids are used in drilling through pay zones is to avoid the invasion of solids into the formation. Solids are a mainstay of drilling muds. They not only give muds much needed weight, but are responsible for forming the filter cake that seals off the formation during drilling.

A good mud cake is essential to avoid lost circulation while drilling, but in the production zone of a well, this cake must eventually be removed so the well can be effectively produced. If there are solids in the formation, it is more difficult to remove the cake without causing formation damage. Drill-in fluids are cleaner than muds, but still leave a filter cake and contain various polymers to create the viscosity needed to transport out cuttings. The majority of these fluids are made up of starch, cellulose, or xanthan polymers, plus bridging agents such as sized calcium carbonate or salt particles. Some of these polymers invade the formation near the hole creating a "skin". This is a damaged area around the wellbore that impedes productivity. In multilateral and horizontal completions this can be a serious problem because of the extensive open-hole pay zones and high costs of such wells.

If there is formation damage clean up methods are used to try and remove the polymers without further damage in the formation. Traditionally, oxidizers, such as bleach, and acid treatments are used to remove the polymers. While these do help, there are limitations to these techniques. Sodium hypochlorite, lithium hypochlorite, persulfates, and acids are not designed to react with specific polymers and attack the polymer chain at any available site. The bleach is a free radical that attacks anything downhole, including the tools and tubulars. Acids and other agents react with a maximum of two sites per molecule so they are spent rapidly.

Once the oxidizing agents are spent the remaining fragments of polymers will not continue to break down and can clog pore throats and slotted liners. Bleach type agents can eat up the wellbore, while acids cut "worm holes" into the formation.

BJ Services markets a clean-up product called Mudzymes that are polymer-specific enzymes matched with the drill-in fluids. These Mudzymes degrade only the polymers in the drill-in fluids without damaging the formation. These linkage specific enzymes align with a cleavage site to totally degrade a polymer strand. The Mudzymes continue to break down the polymers as long as they are in contact with them.

Future applications

Several companies are currently studying the crystalization temperature of standard brines. While this has been know for years, in deepwater fields, high pressures from the mudline affect the crystalization temperature. As more deepwater well are drilled and completed, the industry is striving to better understand the effects these pressures have on the crystalization of brines.

Formate brines and acetate brines are now being introduced into the market along with higher density drill-in fluids. These fluids are popular in horizontal applications where the pay zone is very long.