Historically, invert emulsion drilling fluids have been the systems of choice for ultra-deep HP/HT wells. Environmental restrictions in effect in Central Europe, however, dictate that systems include no oil- or diesel-based fluids or additives that incorporate chrome, which is highly effective in controlling rheology. These operating conditions spurred researchers to launch a program to develop an aqueous system specifically for these HP/HT wells.

The technical demands associated with developing a water-based fluid for the HP/HT environment were formidable.

HT gelation is an overriding problem with water-based muds even in routine applications but is magnified considerably in deep HP/HT wells. Gelation is caused when clay or bentonite in the fluid flocculates. Aqueous systems require very tight control of the solids content along with selecting thermal-stable products for treatment. HT gelation and degradation of product and mud properties increase HP/HT fluid loss. With drilling fluid densities approaching 17 lb/gal, barite sag can impact the entire operation.

A wealth of potential

The unconventional tight sands of basin-centered gas exploration in Hungary and elsewhere in Central Europe constitute a huge resource that, if developed, could significantly revive exploration and gas production in similar environments.

The problem is basin-centered gas accumulations are deep, with some wells in the region being drilled to nearly 20,000 ft (6,096 m). These ultra-deep HP/HT wells require mud densities above 16 lb/gal.

Bottomhole static temperatures (BHST) of more than 356°F (170°C) and expected shut-in pressure of greater than 10,000 psi are troublesome enough, but the technical demands are compounded dramatically when the presence of acidic gases such as CO2 and H2S is taken into account. The challenges are multiplied
in this environmentally sensitivity area where the use of more technically proficient oil-base drilling fluid is prohibited.

Historically, these and other technical restrictions have severely limited drilling fluid selection and have resulted in failure to reach the desired drilling objectives.

System design
Engineering a new water-based fluid for extreme HP/HT conditions carried with it a host of demanding objectives. The system had to have controllable fluid loss and exhibit property stability and contamination tolerance at densities greater than 16 lb/gal and temperatures to 500°F (260°C). The system also had to withstand CO2 and H2S contamination. Best practices and engineering guidelines had to be developed specifically for the new system.

As a starting point, “conventional” formulations without chrome-based products of various mud systems used in past were tested at temperatures from 392°F to 410°F (200°C to 210°C). Not surprisingly, the systems broke down at these elevated temperatures with the inclusion of any contaminant. Very high rheology was observed, with some samples appearing almost dry after aging. Several other tests and combinations of products were tested using different concentrations of HT products or polymers, oxygen scavengers, anti-oxydants, and other materials. Still, acceptable rheological properties and reasonable values for HP/HT fluid loss were not obtained. It was clear that a new strategy was necessary and, most importantly, different products were required.

An analysis of previous work resulted in a number of changes for the formulation of the system and for the lab testing procedure. These included selecting only products rated for stability to 482°F (250°C) and reducing the number of products in the system to allow more free water and obtain a lower rheology at high mud weights. Products that bestow highest rheology without significant help for HP/HT fluid loss were omitted as were those determined to be affected by acid gases.

Testing

With ultra-HP/HT wells, it is nearly impossible to simulate in the lab the exact field conditions a fluid is exposed to at any given time; so a new testing protocol was needed.
Though downhole temperatures can be created in the lab, products in the field are exposed gradually to higher temperatures, and concentrations build step by step. The volume scale in the lab is also much lower, and in laboratory testing, continuous treatment is not possible, which raises the question of what temperature in the lab corresponds to the actual BHST.

A rule of thumb that lab temperature be 50°F (10°C) lower than the BHST was not followed in this case because operators generally want tests to be done at the anticipated BHST. All of the tests for ultra-HT fluids were performed in at least two steps.

First, the systems were built and aged at an intermediary temperature of 302°F (150 °C) in this case to allow complete dissolution and “thermal activation” of their functions. Afterward, the pH and free calcium content were adjusted and the system aged at the final temperature. For this project, the final temperatures were 482°F (250°C), 446°F (230°C), and 410°F (210°C).

With the protocol developed, tests were continued and repeated until a simplified formulation yielded encouraging results. Both rheology and HP/HT fluid loss were good when measured at 392°F (200°C) and 500 psi differential, and the HT gelation (observed on previous tests and field applications) was eliminated, obtaining good rheology for the first time.

The formulation comprised four key products:
• An acrylamide copolymer (HP/HT fluid loss and viscosity)
• Sulphonated asphalt (HP/HT fluid loss control and rheology control)
• Dispersed coupled gilsonite (HP/HT fluid loss and viscosity); and
• Potassium-causticized lignite (rheology control and HP/HT fluid loss).
A small quantity of bentonite was also added to help build the filter cake and to reduce fluid loss. Caustic soda and lime were added for alkalinity and calcium, with triazine hydrosyalkyl incorporated as an H2S scavenger.

Testing continued to screen the products used and to determine which ones are most suitable in ultra-HT applications, particularly with respect to providing effective rheology control. Thus, a simplified base fluid was treated separately with causticized lignite, sulphonated asphalt, resinated lignite, gilsonite, glycol, or a combination thereof.

Additional samples were aged at the intermediary temperature of 302°F, then at the final temperature 446°F, with plastic viscosity, yield point (YP), and API fluid loss measured after each step.

Initial results were mixed, but more intensive evaluation revealed meaningful results. First, it was confirmed that the HT products have mixed rheology and that API fluid loss results in the two temperature ranges. Even when absolute values at the intermediary temperature were not within a good range, tests continued because the main interests were to evaluate the system’s exposure to ultra HT environments and to evaluate qualitative rather than quantitative trends.

The results

The test resulted in important observations. For one thing, time and temperature have tremendous influences over HT products for ultra-hot applications. Consequently, in the field, engineers should not be concerned by initial high rheology and should build up concentrations slowly and under temperature exposure. For another, gilsonite, causticized-lignite, and sulphonated asphalt are ideal for controlling rheology and HT gelation in extreme temperatures.

The most important observation was that even at the intermediate temperature in the HT range, the resinated lignite provided lower rheology. Further, all products showed very good API fluid loss values while HP/HT fluid loss values improved as well from the base fluid.

With this knowledge, a new series of tests has been initiated to determine which products are best in controlling the HP/HT fluid loss in ultra-high temperature applications.

The follow-up test used as the base fluid a field sample from an ultra-hot well in Hungary. The base sample was treated with various products and aged at 446°F for 16 hours.

Based on these extensive tests and corroboration with field applications in Hungary, the four products mentioned previously were selected as key ingredients for the new water-based ultra-high-temperature drilling fluid.

Field considerations

Field applications are not straightforward. Temperatures increase gradually, and the system accumulates drilled solids from previous intervals.

An actual ultra-HT application starts with a superior-inhibition water-based system, and once the temperature starts to elevate, HT products are added gradually. Of crucial importance is the solids content, which is maintained as low as possible.

Once in the HT interval, the Methylene-Blue Test for cathion exchange capacity value should be reduced to less then 25 kg/cu m and less then 10-12 kg/cu m on entering the ultra-HT interval.

Successful system engineering requires experienced personnel and understanding of the phenomenon and reactions taking place under ultra-HT conditions.