New water-based drilling fluid with treated micronized barite slurries may help reduce ECDs

Posted on 03 November 2009

By Ole Iacob Prebensen, M-I SWACO

Technical challenges in the oil industry are becoming more complex each day. Ten- to 12-km wells are being drilled, ultra high-temperature, high-pressure wells are being planned, and wells with very limited hydraulic windows are no longer the exception. On the Norwegian Continental Shelf (NCS), the North Sea is regarded as a mature area, though it contains several of the largest discoveries on the NCS. To gain access to the remaining hydrocarbons, new drilling methods such as managed pressure drilling and drilling with casing have been used.

At the same time, environmental protection has come into greater focus because the entire NCS is regarded as an environmentally sensitive area. With drilling operations expanding northward into the Barents Sea and perhaps beyond, the environmental impact of drilling operations has become a very sensitive topic. For example, there is ongoing conflict between NGOs and the fishing industry on one side and the development of oil and gas on the other. The Norwegian government also has decided that no discharge of drill cuttings or drilling fluids to the sea is allowed. These facts are all cause for a rethinking of drilling operations and waste-handling among service companies and operators.

Critical technical challenges that operators face on the NCS with respect to drilling operations include equivalent circulating density (ECD) limitations, depleted reservoirs, limited hydraulic windows and losses to the formations. Hole cleaning, transfer of experience, slop and waste handling, exposure to vapor from use of oil-based drilling fluids and conversion to environmentally acceptable products are all important factors to be considered. No single solution exists that will deal with all of these topics at the same time, and the challenges add to the complexity of future operations.

 High-performance OBMs use low kinematic viscosity base oils to help reduce the equivalent circulating density.

As an example, there is a natural conflict between using very low-viscosity base oil for reduced viscosity in the drilling fluid and, at the same time, having low vapor from the same base oil. A compromise must be made.

But one drilling fluid supplier raised this question: How could several of these challenges be solved with one single drilling fluid system? Would it be possible?
Most drilling fluid suppliers have in their portfolio what is regarded as a high-performance oil-based drilling fluid (OBM). Such a fluid uses low kinematic viscosity base oils, which contribute less to the overall viscosity of the drilling fluid. This, in turn, helps to reduce the ECD compared with a more conventional drilling fluid where higher kinematic viscosity base oils are used. Some low-viscosity base oils are mineral oils, but some high-performance OBMs use linear paraffins in the external phase.

There are two areas where use of linear paraffins causes concerns for the drilling operation.

First, while linear paraffin provides very good viscosity profiles, its high pour point can cause problems. There is a tendency for oil-based drilling fluids with linear paraffins to gel up in cold-temperature conditions. The challenge occurs once circulation stops and the drilling fluid temperature cools down. On some platforms, the temperature at seabed can be as low as 4°C (39°F). In deepwater wells, the seabed temperature can be -2°C (28°F).

Even if oil-based drilling fluids are rarely used in deepwater applications on the NCS, most existing platforms use OBMs in drilling production wells.
Second, during the drilling of a well, the temperature in the flow line might reach 60-75°C (140-167°F) or even above. Vapor from linear paraffins is higher than from mineral oils, which raises the exposure risk for rig crews.

A comprehensive study by an operator and a drilling fluids supplier concluded that base oil and emulsifier are the main causes for the vapor generated. As a result and after years of research, a new mineral oil with low kinematic viscosity – almost identical to the viscosity of linear paraffins – has been developed. This new base oil also has lower vapor than their counterparts, which reduces the impact of exposure for crews.

REDUCING HSE IMPACT

Bear in mind that regardless of what base oil is used, no discharge of OBMs is allowed for any reason on the NCS. But by using a new oil-based drilling fluid that contributes less to vapor than current products, the HSE impact and challenges of using OBMs can be reduced.

It is commonly accepted that OBMs are superior in technical performance to water-based drilling fluids (WBM). The most obvious reason is that shales and reactive formations do not swell in an OBM. In addition to being highly inhibitive, with reduced torque and drag, higher rate of penetration, temperature stability and being noncorrosive, OBMs have a very good tolerance towards contaminations.

The downside to using OBMs compared with WBMs is the HSE aspect. Anywhere on the NCS, drilled cuttings from OBM operations must be collected and shipped onshore for treatment if cuttings reinjection wells do not exist. This contributes to an increase in drilling cost.

Based on these facts and the challenges listed by operators, a research project was started in 2007 with the main goal of developing a WBM with superior quality and performance. From a technical perspective, the main objective was to develop a very inhibitive system to deal with the bit balling and cuttings accretion seen with some WBMs. At the same time, the system should provide minimum impact to ECD from the viscosity of the fluid, be barite sag-resistant and have good tolerance toward contaminants.

Because several hundred wells had already been successfully drilled and completed with OBM where treated micronized barite slurries (TMBS) are used as the weighting agent, the focus here was set on using the same technology in a water-based version.

The main challenge was finding the best available shale inhibitors. A large screening process of readily available and experimental shale inhibitors and anti-accretion products was performed. Specific laboratory tests were run with different combinations of these products, in combination with the water-based version of the TMBS. These tests were:

• Accretion, defined as the mechanism by which partially hydrated cuttings stick to parts of the bottomhole assembly and accumulate as a compacted, layered deposit.

• Recovery, which is the hot roll/dispersion test designed to give an assessment of the inhibition of shale cuttings exposed to a drilling fluid. Following the aging period, the cuttings are screened from the fluid and gently washed with brine water, then dried and reweighed. The amount of cuttings recovered is a measurement of the fluid’s inhibition.

• Cuttings hardness, which is an experiment designed to give an assessment of the hardness of shale cuttings exposed to a drilling fluid. The hardness of the shale cuttings relates to inhibitive properties of the fluid being evaluated.

To find the best shale inhibitors, cuttings hardness was tested in lab tests using different combinations of shale inhibitors with water-based

versions of TBMS.

Based on results from these laboratory tests, it was observed that this new WBM provides a lower viscosity profile than any of the other water-based systems tested, without compromising sag performance. Shale inhibition tests, including accretion, cuttings hardness and recovery, concluded that the system is a very inhibitive fluid, with best overall performance compared with other known water-based systems. Lower viscosity from the system improves ECD values and should allow higher permissible flow rate. Near-zero barite sag values were observed in the laboratory – even under harsh testing conditions. Good fluid loss control and lower co-efficient of friction were also achieved with this new WBM.

Initial hydraulic comparison among a high-performance WBM, a conventional OBM and this new WBM indicate that a reduction in pump pressure and lower ECDs can be achieved with the new system. It’s assumed that this system will contribute to a reduction in dilution rates as the fluid is based on TMBS technology. Finer mesh shaker screens could likely be used with the system to enhance the potential for re-use. This drilling fluid system will soon be field-tested on the NCS.

Ole Iacob Prebensen is technology manager at M-I SWACO’s European Technical Center.

1 Comments For This Post

  1. Geir Eikeland Says:

    Cubility is producing a new type Shale Shaker, which should take part of a shaker test.

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