Scholarly article on topic 'Comparative study of using Water-Based mud containing Multiwall Carbon Nanotubes versus Oil-Based mud in HPHT fields'

Comparative study of using Water-Based mud containing Multiwall Carbon Nanotubes versus Oil-Based mud in HPHT fields Academic research paper on "Materials engineering"

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Abstract of research paper on Materials engineering, author of scientific article — M.I. Abduo, A.S. Dahab, Hesham Abuseda, Abdulaziz M. AbdulAziz, M.S. Elhossieny

Abstract Water-Based mud (WBM) and Oil-Based mud (OBM) are the most common drilling fluids currently used and both have several characteristics that qualify them for High Pressure High Temperature (HPHT) purposes. This paper compares the different characteristics of WBM containing Multiwall Carbon Nanotubes (MWCNTs) and OBM to help decide the most suitable mud type for HPHT drilling by considering mud properties through several laboratory tests to generate some engineering guidelines. The tests were formulated at temperatures from 120°F up to 500°F and pressures from 14.7psi to 25,000psi. The comparison will mainly consider the rheological properties of the two mud types and will also take into account the environmental feasibility of using them. The results showing that the Water-Based offers a more environmental friendly choice yet some of additives that are used to enhance its performance at (HPHT) conditions, such as (MWCNTs), thus it is necessary to develop new formulas for (HPHT) Water-Based muds that could act like Oil-Based mud but cause less harm to the environment.

Academic research paper on topic "Comparative study of using Water-Based mud containing Multiwall Carbon Nanotubes versus Oil-Based mud in HPHT fields"

Egyptian Journal of Petroleum (2015) xxx, xxx-xxx

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Egyptian Petroleum Research Institute Egyptian Journal of Petroleum

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Egyptian Journal of Petroleum

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Comparative study of using Water-Based mud containing Multiwall Carbon Nanotubes versus Oil-Based mud in HPHT fields

M.I. Abduo a, A.S. Dahab b, Hesham Abusedaa, Abdulaziz M. AbdulAzizb, M.S. Elhossieny a'*

a Egyptian Petroleum Research Institute, Nasr City, Cairo, Egypt b Cairo University, Faculty of Engineering, Department of Petroleum, Cairo, Egypt

Received 25 May 2015; revised 15 September 2015; accepted 12 October 2015

KEYWORDS

Water-Based mud; Oil-Based mud; Multiwall Carbon Nanotubes; HPHT

Abstract Water-Based mud (WBM) and Oil-Based mud (OBM) are the most common drilling fluids currently used and both have several characteristics that qualify them for High Pressure High Temperature (HPHT) purposes. This paper compares the different characteristics of WBM containing Multiwall Carbon Nanotubes (MWCNTs) and OBM to help decide the most suitable mud type for HPHT drilling by considering mud properties through several laboratory tests to generate some engineering guidelines. The tests were formulated at temperatures from 120 °F up to 500 °F and pressures from 14.7 psi to 25,000 psi. The comparison will mainly consider the rheological properties of the two mud types and will also take into account the environmental feasibility of using them. The results showing that the Water-Based offers a more environmental friendly choice yet some of additives that are used to enhance its performance at (HPHT) conditions, such as (MWCNTs), thus it is necessary to develop new formulas for (HPHT) Water-Based muds that could act like Oil-Based mud but cause less harm to the environment.

© 2015 Production and hosting by Elsevier B.V. on behalf of Egyptian Petroleum Research Institute. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/

4.0/).

1. Introduction

Drilling fluids are usually formulated to meet certain properties to enable them to carry out the basic intended functions. The most prevalent problem affecting the drilling fluids in HPHT conditions is the potential destruction of the mud

* Corresponding author.

E-mail address: s33d_2010@yahoo.com (M.S. Elhossieny).

Peer review under responsibility of Egyptian Petroleum Research

Institute.

properties under such elevated pressures and temperatures. Hence it requires a proper balance of mud properties to avoid oil and gas surge, kicks, formation damage and other drilling hazards associated with HPHT oil and gas wells. For HPHT operations both Water-Based mud and Oil-Base mud have been used, however, in reality Oil-Based mud is more widely used to overcome problems in HPHT conditions [1].

A drilling fluid must have the ability to drill the formation where the bottom hole temperatures are excessively high, and especially in the presence of contaminants. Oil-Based muds can

http://dx.doi.org/10.1016/j.ejpe.2015.10.008

1110-0621 © 2015 Production and hosting by Elsevier B.V. on behalf of Egyptian Petroleum Research Institute. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/).

be formulated to withstand high temperatures over long periods of time, however, Water-Based mud can break down and lead to loss of viscosity and fluid loss control. Some other advantages of the application of Oil-Based mud are shale stability, faster penetration rates, providing better gauge hole and not to leach out salt [2].

It should be mentioned that Oil-Based mud is not always feasible. The initial cost of Oil-Based mud is high, especially those formulations based on mineral or synthetic fluids. Sometimes this high cost can be offset by Oil-Based mud buy-back program offered by service companies. Kick detection is more challenging when using Oil-Based mud compared to Water-Based mud. This is due to high gas solubility in Oil-Based mud. Lost circulation is also very costly for OBM operations [3]. Greater emphasis is also placed on environmental concerns when using Oil-Based mud as related to discharge of cuttings, loss of whole mud and disposal of the Oil-Based mud. Special precautions should be taken to avoid skin contact with OBM which may promote allergic reactions inhalation of fumes from Oil-Based mud that can be irritating [4]. Oil-Based mud can be damaging to the rubber parts of the circulating system and preclude the use of special oil resistant rubber. It has posed potential fire hazards due to low flash points of vapors coming off the oil. Additional rig equipment and modifications are necessary to minimize the loss of Oil-Based mud [5].

In the past HPHT was attributed to any condition with pressure or temperature above the atmospheric condition. Service companies, operators, cement/drilling fluid testing equipment companies and other pipe or tools manufacturers, each, came up with a slightly different definition for HPHT condition [6].

Environmental and economical considerations have led to the increasing use of Water-Based drilling fluids (WBM) in applications where Oil-Based drilling fluids (OBM) have previously been preferred, including high-temperature, high pressure (HTHP) wells. In an increasing number of areas in the world environmental regulations prohibit the discharge of Oil-Based mud and cuttings containing OBM. These HTHP wells can be defined as those with a bottom hole temperature between 300 0 and 500 0F and an expected shut-in pressure from 10,000 psi to 25,000 psi [7]. Dispersed WBM are among the most popular drilling fluids; thanks in part to their reputation as easy to maintain, economically competitive drilling fluids. Such fluids can be designed and engineered to be suitable for HTHP environments.

To improve the rheological stability and fluid-loss properties of these fluids at elevated temperatures, Multiwall Carbon Nanotubes (MWCNTs) additives have been successfully applied. Water-Based mud (WBM) and Oil-Based mud (OBM) are the most common drilling fluids currently used and both have several characteristics that qualify them for HPHT purposes. This paper compares the different characteristics of WBM and OBM to help decide the most suitable mud type for HPHT drilling by considering mud properties through several laboratory tests to generate some engineering guidelines. The tests were formulated at temperatures from 120 of up to 500 of and pressures from 14.7 psi to 25,000 psi. The comparison will mainly consider the rheological properties of the two mud types of mud and will also take into account the environmental feasibility of using them [8].

This paper presents a culmination summary of the results from extensive testing that demonstrates the optimal

combination of chemistries that are needed to perform like a well-designed dispersed Water-Based mud with Multiwall Carbon Nanotubes additives. Mixing and addition conditions were established and controlled to both optimize additive performance and to ensure a good comparison between formulations. The general specifications that were set to define the performance of the ideal fluid included a Plastic Viscosity (PV) of less than 30 cP, a 6-rpm reading between 7 and 10, and HTHP fluid-loss filtrate of less than 30 ml at 300 0F (149 oc), and 500-psi differential pressure on hardened paper. The rheological properties were measured at 150 of (66 oc). API low-temperature/low-pressure fluid loss as described was used as a screening tool to determine which fluids would be selected for fluid-loss evaluation under HTHP test conditions. Ultimately, slumping may result in barite accumulation and a pronounced density change within the drilling fluid [9]. The rheological and filtration loss characteristics of colloidal gas Apron have been investigated before.

2. Experimental procedures and materials

We conducted two separate studies on the rheological properties of an OBM sample and a WBM sample (Table 1) under HPHT conditions using the state-of-art Chandler 7600 HPHT viscometer (Fig. 1). This viscometer was capable of measuring the rheological properties of drilling fluids under high temperatures up to 600 oF and high pressure up to 40,000 psi. Also we used HPHT filter press (Fig. 2) to evaluate the filtration of these two samples.

3. Test procedure

The procedures of the experiment of the drilling fluid properties below followed the API recommendations for drilling fluid testing as best as possible, as some of the recommendations

Table 1 Properties of the two mud samples used in this study.

Sample type Product Grams

Water Based mud Water 291.4

M-I Bar 25

Versa Trol 1

Soda ash 1

Versa Mul 1.5

Versa Mod 10.5

Caco3 (M) 15

Versa gel HT, 4

LVT-200 93.00

MWCNTs According to total weight

Oil Based mud Oil 155.7

Safe carb 15

Lvt-200 27

Mul XT 5

Barite 56

One-Trol Ht, 3

Lime 8

Surewet 19

Cacl2 22.37

Cc-555 1

"Courtesy of MI-Swaco.

(4) Adding various amounts of pure MWCNTs as an additive to the fluid prepared samples.

(5) Mixing all the samples produced at 6000 rpm for 5 min.

(6) Using TEM to take a high resolution image for all samples after adding MWCNTs at different concentrations Fig. 4.

were not representative for the actual bottom hole conditions in this experiment.

(1) Adding 22.5 gr. bentonite to an equivalent bbl of a mud (350 ml) to prepare a 22.5 lb/bbl water based fluid.

(2) Mixing the mud at least for 15 min to prepare a unique fluid.

(3) Using TEM to take a high resolution image for all samples (Fig. 3).

4. Results and discussion

4.1. Effect of MWCNT's on the rheological properties of the Water-Based mud

It is obvious that adding the functionalized MWCNTs to the Water-Based mud increases shear stress; also, shear stress is linearly proportional to shear rate. This phenomenon could be ascribed to the better dispersion of the MWCNTs at high shear rates (i.e. 600 rpm). The comparison of Yield Point (YP) of conventional water base mud and MWCNT's modified mud is investigated for different concentrations of MWCNTS and the results. Generally, the Yield Points of MWCNT-based drilling fluids are higher than those of the conventional Water-Based fluids. So, by adding the functionalized MWCNTs to the Water-Based mud, where the flow regime is laminar, pressure lost slightly increases, especially in those portions of the well bore and drill string. When percentage of MWNTs in the mud increases, the viscosity of water base mud also increased. Therefore, the lifting capacity also increased. The MWNTs are dispersed in water based mud because, water absorbs into it and becomes agglomerated. These phenomena will increase the viscosity of mud. Figs. 3 and 4 show images of bentonite before and after adding MWCNT.

We introduced hydrophilic functional groups to the surface of the nanotubes by acid treatment. Nitric acid (69%) was used to modify the surface of the MWCNTs. In a typical treatment of the present work, one gram of the MWCNTs and 40 ml nitric acid were boiled and refluxed together for 4 h. Then, the sample was diluted by deionized water, filtered, and rinsed repeatedly until the sample showed no acidity. The cleaned

Figure 3 Image of bentonite before adding MWCNT.

Figure 4 Image of bentonite after adding MWCNT.

MWCNTs were collected and dried in an oven for 12 h to remove the attached water. We also milled the MWCNTs for 12 h in those samples which required ball milling as a mechanical dispersion method in order to investigate the effect of ball milling on the thermal properties of the drilling nanofluid.

4.2. Rheological properties of Water-Based mud versus Oil Based mud

4.2.1. Viscosity

Viscosity is the representation of a fluid's internal resistance to flow, defined as the ratio of shear stress to shear rate. Viscosity is expressed in poise

shear stress

shear rate

Dyne, sec

(defined as poise)

A poise is a very large number and therefore, viscosity is typically reported in centipoise (100 centipoise = 1 poise).

Fig. 5 and Table 2 compare the dial reading values (which correspond to the viscosity) for the Oil-Based and the Water-Based mud samples at different temperatures and different pressures. The plots show that the viscosity of the sample slightly decreases as pressure increases and decreases as temperature increases (inversely proportional) for both samples. Generally, the Oil-Based mud sample expresses higher dial readings (viscosity) than the Water-Based sample.

4.2.2. Yield Point

Yield Point (YP) as the initial resistance to flow caused by electrochemical forces between the particles is a parameter of the Bingham plastic model. It is the yield stress extrapolated to a shear rate of zero. Bingham plastic fluid plots are a straight lines, a shear rate on x-axis versus a shear stress on y-axis and the obtained Yield Point is the zero-shear-rate intercept. Plastic Viscosity (PV) is the slope of this line. Yield Point is

15 10 5

Rheology properties

AV. Cp

■ PV. Cp

■ YP. lb/100ft2

1 atm 1 atm 15000 15000 20000 20000 25000 25000

&120 f &120 f psi psi psi & psi & psi & psi &

(oil) (water) &350 f &350 f 400 f 400 f 500 f 500 f

(oil) (water) (oil) (water) (oil) (water)

Pressure and Temperature

Figure 5 Yield Point, plastic viscosity and apparent viscosity values versus temperature for different pressures.

calculated from 300 to 600 RPM viscometer dial readings by subtracting PV from the 300 RPM dial reading. Yield Point is dependent upon the surface properties of the mud solids and also the volume concentration of the solids. Yield Point could be used to evaluate the ability of a mud to lift cuttings out of the annulus. Yield Point (YP) is calculated from VG measurements as follows:

YP = 0300 - (0600 - 0300) or YP = 6300 - PV

Fig. 5 shows the Yield Point values for the two mud samples with temperature for different pressures. Similar to viscosity, Yield Points plot for both mud samples shows that it is generally higher at low temperatures and pressures. The Yield Point for the Oil-Based mud was much higher than the Water-Based mud, which enhances the drilling operation.

4.2.3. Gel strength

Gel strength is the shear stress measured at low shear rate after a mud has set quiescently for a period of time (10-s and 10-min in the standard API procedure, although measurements after 30-min or 16-h may also be made), it indicates strength of attractive forces (gelation) in a drilling fluid under static conditions. Excessive gelation is caused by high solid concentration leading to flocculation.

Signs of rheological trouble in a mud system often are reflected by a mud's gel strength development with time. When there is a wide range between the initial and 10-min gel readings they are called ''progressive gels". This is not a desirable situation. If initial and 10-min gels are both high, with no appreciable difference in the two, these are ''high flat gels", also undesirable. The magnitude of gelation with time is a key factor in the performance of the drilling fluid.

Excessive gel strengths can cause; swabbing when pipe is pulled, surging when pipe is lowered, difficulty in getting logging tools to bottom, retaining of entrapped air or gas in the mud, and retaining of sand and cuttings while drilling.

Gel strengths and Yield Point are both a measure of the attractive forces in a mud system. A decrease in one usually results in a decrease in the other; therefore, similar chemical

Table 2 Water Based mud and oil Based mud results.

Sample No. AV. cP PV. cP YP. lb/100 ft2 10' 10'' Thix.

1 atm and 120 f (oil) 40 25 30 12 14 2

1 atm and 120 f (water) 37 24 26 11 13 2

15,000 psi and 350 f (oil) 36.5 24 25 10 12 2

15,000 psi and 350 f (water) 34 24 20 9 12 3

20,000 psi and 400 f (oil) 27.0 19 16 8 10 2.0

20,000 psi and 400 f (water) 25.0 18 14 7 9 2.0

25,000 psi and 500 f (oil) 22.5 15 15 9 12 3.0

25,000 psi and 500 f (water) 20.0 11 18 7 12 5.0

treatments are used to modify them both. The 10-s gel reading more closely approximates the true yield stress in most drilling fluid systems. Water dilution can be effective in lowering gel strengths, especially when solids are high in the mud. Fig. 6 shows the 10-s gel strength for the Oil Based mud sample and Water-Based mud.

5. Environmental consideration in using OBM and WBM for HPHT drilling

Oil-Based mud may be selected for special applications such as high temperature or high pressure wells, minimizing formation damage and other reason for choosing Oil-Based fluids is that they are resistant to contaminants such as anhydrite, salt, and CO2 and H2S acid gases. Oil-Based mud is effective against all types of corrosion and has superior lubricating characteristics, and sometimes it even permits mud densities as low as 7.5 lb/gal.

Cost can be one of the concerns when selecting Oil-Based muds. Initially, the cost per barrel of an Oil-Based mud is very high compared to a conventional Water-Based mud system. However, because Oil-Based mud can be reconditioned and reused, the costs on a multi-well program may be comparable to using Water-Based fluids. Also, buy-back policies for used Oil-Based mud can make them an attractive alternative in situations where the uses of Water-Based mud prohibit the successful drilling and/or completion of a well.

Today, with increasing environmental concerns, the use of Oil-Based mud is either prohibited or severely restricted in many countries. Environmental regulations restrict and prohibit the use of drilling fluids that have the potential to pollute the soil and ground water aquifers.

Gel strength

&120 f &120 f psi psi psi& psi & psi & psi & (oil) (water) &350 f &350 f 400f 400f 500f 500f (oil) (water) (oil) (water) (oil) (water)

Pressure and Temperature

Figure 6 Gel strength values versus temperature for different pressures.

Oil-Based drilling fluids are thus prohibited in many countries around the globe such as the USA, United Kingdom, Holland, Norway, Nigeria, European countries, Saudi Arabia, and Qatar. In some areas, drilling with Oil-Based fluids requires the used mud and cuttings to be contained and hauled to an approved disposal site. Discharges of cuttings from Oil-Based mud drilling operations can have an adverse effect on the seabed biological habitat in the immediate vicinity of the platform, and this is due mainly to physical burial of the natural sediment. The spread of cutting particles is greatly influenced by their particle size and the prevailing current regime. However, it is believed that cuttings, particularly from Oil-Based mud drilling operations, fall more directly to the seabed as a result of agglomeration.

The extent of biological effect is greater from Oil-Based mud cuttings than from Water-Based mud cuttings. Beyond the area of physical smothering, the effects of Oil-Based mud cuttings may be due to organic enrichment of the sediment and/or the toxicity of certain fractions of the oils used, such as aromatic hydrocarbons. It has not been possible from the data available at present to distinguish between the ecological effects of diesel mud and alternative base muds. As more data on the effects of the use of alternative muds become available it may be possible to elaborate on this issue. Despite the scale of inputs, in all fields studied, the major deleterious biological effects were confined within a 500 m radius and associated primarily with burial under the mound of cuttings on the seabed. Seabed recovery in this zone is likely to be a long process.

Which more subtle biological effects can be detected as community parameters return to normal, generally within 200-1000 m. The shape and extent of this zone are variable, and are largely determined by the current regime and the scope of the drilling operation. In areas with stronger bottom currents and more extensive drilling, this zone may be extended to 2000 m in the direction of greatest water movement. From the little information which is available, the surface sediments studied in this zone appeared to be aerobic and biodegradation of hydrocarbons seems to be taking place. Thus a more rapid recovery of the transition zone is expected on cessation of drilling.

The costs of containment, hauling, and disposal can greatly increase the cost of using Oil-Based fluids. Water-Based mud is less harmful to the environment which makes it a preferred option for HPHT drilling in these countries. Water-Based mud with the same performance characteristics of invert emulsion drilling fluid is becoming available now which can has applications in HPHT condition. MWCNT materials are environmentally friendly and they are part of some

high-temperature Water-Based fluids, acting as an efficient and stable dispersant and fluid loss control agents. New Nano materials for high temperature and high pressure have been introduced in stable Water-Based drilling fluid system by using a combination of clay and MWCNTs to provide a stable rhe-ology and fluid loss. This calls for designing an HPHT tolerant Water-Based mud with an eco-friendly formulation.

6. Conclusions

High pressure and high temperature operations seem to be a new normal for oil and gas industry. Drilling into the reservoirs with elevated pressures and temperatures requires a fluid with stable rheological properties. This study shows that Water-Based mud contains Multiwall Carbon Nanotubes (MWCNTs) and OBM to help decide the most suitable mud type for high temperature/high pressure conditions drilling by considering mud properties through several laboratory tests to generate some engineering guidelines.

Oil-Based mud is a proper choice for most of the HPHT applications if not violating the environmental regulations. Designing an eco-friendly Water-Based mud is a necessity for HPHT drilling. A new environmentally safe water based containing Multiwall Carbon Nanotubes (MWCNTs) system has been tested for drilling application with temperatures up to 500 oF. The system components are newly developed and do not contain any environmentally harmful materials.

Acknowledgments

The authors would like to thank Emic for their exhaustive

research and also MI-SWACO for supporting this research

and for allowing us to publish this report.

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