Enhancing the performance of Xanthan gum in water-based mud systems using an environmentally friendly biopolymer

Xanthan gum is commonly used in drilling fluids to provide viscosity, solid suspension, and fluid-loss control. However, it is sensitive to high temperatures and not tolerant of field contaminants. This paper presents an experimental study on the effects of an eco-friendly biopolymer (diutan gum) on xanthan gum (XC) in a water-based bentonite mud. Laboratory experiments were carried out for different compositions of the biopolymers in water-based bentonite muds formulated without salt and in water-based bentonite muds containing sodium chloride (NaCl). The rheological properties of the water-based bentonite muds formulated with XC (2 Ibm) and those of the water-based bentonite muds prepared using XC (1Ibm) and diutan gum (1Ibm) were measured using Model 1100 viscometer after aging at 25 °C, 100 °C, and 120 °C for 16 h. The API fluid loss and filter cake of the mud formulations were measured using HTHP filter press. The properties of the water-based bentonite muds containing only XC were compared with those of the water-based bentonite muds containing XC and diutan gum. Presented results show that combining diutan gum and xanthan gum in a ratio of 1:1 in a water-based bentonite mud enhances its performance with respect to fluid properties—apparent viscosity, gel strength, yield points, YP/PV ratio, LSRV, n, and K. The fluid formulations also showed favorable mud cake building characteristics. Experimental data also indicate a 16%, 19%, and 34% reduction in API fluid loss values for the water-based benitoite muds containing XC in the presence of diutan gum after aging at 25 °C, 100 °C, and 120 °C for 16 h, respectively. Experimental results also show that the water-based benitoite mud containing XC and diutan gum would cause less formation damage and was tolerant of contamination with a monovalent cation (Na+). The synergy of xanthan gum and diutan gum can, therefore, improve the performance of water-based drilling fluids

Compressed natural gas : gas distribution option for Sub-Saharan West Africa

Natural gas production in Sub-Saharan West African is projected to grow annually by 5% from 2010 to 2040. The distribution of this gas is vital to economic growth in the sub region. Compressed Natural Gas (CNG) which is natural gas that has been compressed under high pressure and held in hard containers is proposed as an alternative method of natural gas distribution option for the sub-region to pipeline and LNG options especially for short distances within marine environments. The economic prospects of marine distribution of CNG within the West African region was studied and compared to the present West African Gas Pipeline (WAGP) distribution option. A discounted cash flow model was used to compare the economic viability of both projects. The CNG project had higher net present value of $1,914 compared to$695 for the WAGP project. Payback period of 4.7 years and 11 years were respectively obtained for the CNG and WAGP projects. Based on these economic indicators, it could be concluded that the CNG project surpassed the economic performance of the WAGP project. Results from this work could be applied in the study of CNG marine distribution for similar geographical locations around the world

Stabilizing biopolymers in water-based drilling fluids at high temperature using antioxidants, a formate salt, and polyglycol

Biopolymers degrade in water-based drilling fluids when exposed to high temperatures for some time, thus leading to hole-cleaning problems such as stuck pipe. To stabilise biopolymers in drilling fluids, the mechanisms by which they degrade at elevated temperatures must be understood. The degradation mechanisms of thermally labile biopolymers, therefore, include acid-catalysed hydrolysis and oxidation-reduction (redox) reactions. In this paper, an attempt is, therefore, made to investigate whether the combination of anti-oxidants, formate salt, and polyglycol could stabilise biopolymers in water-based drilling fluids with pH 8 to 10 above 200°C. Novel clay-based drilling fluids were formulated with sodium carbonate, sodium bicarbonate, biopolymers, antioxidants, a formate salt, a defoamer and polyglycol. The rheological properties of the drilling fluid formulations were measured using Model 800 and Model 1100 viscometers before and after hot-rolling dynamically in a roller oven for sixteen hours to condition the fluids. Presented results showed that xanthan gum in bentonite-water suspension remained stable up to 1000°C, and konjac gum in bentonite-water suspension remained stable up to 65°C. Experimental data also indicated that after dynamic aging for 16 hours, the antioxidant, formate salt and polyglycol increased the stability temperatures of the biopolymers - konjac gum and xanthan gum – in water-based drilling fluid formulations above 200°C. The best additives package that increased the stability temperatures of the biopolymers was potassium formate, sodium erythorbate, and 0.7% polyethene glycol. This additive package also maintained the suspension capability of the drilling fluid formulations. These additives can, therefore, be used to stabilise water-based drilling fluids containing biopolymers in the 150-232°C temperature range without using expensive and formation damaging synthetic polymers

Experimental investigation of methane-water and methane-brine IFT measurements using pendant drop (rising bubble) method

Gas hydrate formation involves low molecular gas mass transfer to a cage-like structure formed by water molecule under low temperature and high-pressure conditions. Gas hydrate is considered a problem if it develops along a pipeline. In order to solve the problem of gas hydrate formation in the pipeline, there is a need to understand the Interfacial Tension (IFT) behaviour at gas-water interface. This paper presents an experimental investigation of IFT of methane bubble in distilled water and varying concentration of salt (NaCl) using pendant drop (rising bubble) method. The results obtained shows that the IFT decreases with an increase in temperature and pressure. This decreasing trend shows that IFT existing at CH4 – H2O interface is a function of temperature and pressure. Additionally, the concentration of 2.9, 5.6, 8.2 and 10.7wt% NaCl resulted in an average increase of the IFT of the CH4-H2O system in 1.46, 2.57, 3.51 and 4.24 mN.m-1 respectively

Optimization of multi-zone unconventional (shale) gas reservoir using hydraulic fracturing technique

Hydraulic fracturing is one of the most important stimulation techniques available to the petroleum engineer to extract hydrocarbons in tight gas sandstones. It allows more oil and gas production in tight reservoirs as compared to conventional means. The main aim of the study is to optimize the hydraulic fracturing as technique and for this purpose three multi-zones layer formation is considered and fractured contemporaneously. The three zones are named as Zone1 (upper zone), Zone2 (middle zone) and Zone3 (lower zone) respectively and they all occur in shale rock. Simulation was performed with Mfrac integrated software which gives a variety of 3D fracture options. This simulation process yielded an average fracture efficiency of 93.8%for the three respective zones and an increase of the average permeability of the rock system. An average fracture length of 909 ft with net height (propped height) of 210 ft (average) was achieved. Optimum fracturing results was also achieved with maximum fracture width of 0.379 inches at an injection rate of 13.01 bpm with 17995 Mscf of gas production

Water-based drilling fluids for high-temperature applications and water-sensitive and dispersible shale formations

This study examines the effectiveness of sodium erythorbate, potassium formate, and polyethylene glycol for the formulation of high-performance water-based drilling fluids. High-performance water-based drilling fluids are environmentally-friendly, remain stable when exposed to high temperatures, and retard problems associated with reactive shale. A biopolymer, diutan gum, is used as drilling fluid viscosifiers in the preparation of drilling fluid formulations. The viscosities of the drilling fluid formulations with pH 8-10 were measured using Model 1100 viscometer before and after aging dynamically in a roller oven for sixteen hours. Shale rock samples were characterised using scanning electron microscope photos while X-ray diffraction analysis was used to identify the mineral contents of the shale samples. Shale dispersion tests were carried out by aging shale cuttings in an inhibitive drilling fluid formulation and in freshwater dynamically in a roller oven for 16 hours at 120°C. The percentage recovery of shale rocks after dynamic aging was determined. Experimental data indicated that the diutan gum stability temperature in bentonite water-suspension after aging for 16 hours was 115°C. Experimental data also indicated that the mud formulations with the additives - sodium erythorbate, potassium formate, and polyethylene glycol - retained their viscosities up to 232°C. The additives, therefore, significantly retarded the degradation of the biopolymer and other mud additives up to 232°C. The result from the shale dispersion test showed that the shale cuttings recovered from freshwater was 78%; with drilling fluids formulated with the additives, the shale cuttings recovered were 100%. This new fluid system which is stable at high temperatures and inhibits shale dispersion can meet high temperature and shale formation drilling requirements

Impact pressure distribution in flat fan nozzles for descaling oil wells

The suitability of high pressure nozzles in terms of impact upon targeted surfaces has indicated its effectiveness for the cleaning of oil production tubing scale, which has recently attracted wider industrial applications considering its efficiency, ease of operation and cost benefit. In the oil and gas production, these nozzles are now used for cleaning the scale deposits along the production tubing resulted mainly from salt crystallization due to pressure and temperature drop. Detailed characterizations of flat-fan nozzle in terms of droplet sizes and mean velocities will benefit momentum computations for the axial and radial distribution along the spray width, with the view of finding the best stand-off distance between the target scale and the spray nozzle. While the droplet sizes and the velocities determine the momentum at impact, measuring droplet sizes has been known to be difficult especially in the high density spray region, still laboratory characterization of nozzles provides a reliable data especially avoiding uncontrollable parameters. While several researches consider break up insensitive to the cleaning performance, this research investigates the experimental data obtained using PDA (phase doppler anemometry) which led to established variation in momentum across the spray width thus, non-uniformity of impact distribution. Comparative model was then developed using Ansys Fluent code, which verifies the eroded surfaces of material using the flat-fan atomizer to have shown variability in the extent of impact actions due to kinetic energy difference between the center and edge droplets. The study’s findings could be useful in establishing the effect of droplet kinetic energies based on the spray penetration, and will also add significant understanding to the effect of the ligaments and droplets, along the spray penetration in order to ascertain their momentum impact distribution along the targeted surface

The effects of dissolved Sodium Chloride (NaCl) on well injectivity during CO2 storage into saline aquifers

Saline aquifer formations seem to be promising candidates for carbon dioxide (CO2) storage due to their wide availability as well they have large storage capacity. Once CO2 is injected into saline aquifer variety of processes will take place, among of them is the formation dry out and salt precipitation phenomenon, the main driver of this phenomenon is the salinity in the form of Halite (NaCL), this considers a major challenge of CO2 injection into saline aquifers, it causes the risk of formation clogging and will effect on the well injectivity and lead to pressure build up. The selected candidate for carbon dioxide (CO2) storage should meet the technical requirements of sealing integrity, storage capacity (potential) and containment. After the commencement of carbon dioxide (CO2) injection into high salinity formations, formation dry out due to salt precipitation in the near wellbore will take place and this cause permeability and injectivity reduction. This work will focuses on experimental work. The experimental work investigations studied the effectiveness dilution of high sodium chloride NaCl solutions with sea water and its contribution in improving the injectivity. After saturating the sandstone core samples with different brine solutions, linear core flow tests using nitrogen gas (N2) were carried out. The saturated samples in diluted solutions for castlegate sandstone sample showed increase in the flow rate from 4 L/min at 50 psi to 5 L/min at the same pressure, experimentally it was confirmed that dilution of brine solutions by seawater will assist in improving the sandstone core samples porosity , permeability and the injectivity. Keywords- CO2 storage, seawater, CO2/Brine/Rock, Salinity, porosity, permeability CO2 injectiviy

Economic evaluation of environmentally friendly vegetable oil-based invert emulsion

Stringent environmental regulations and technical requirements of difficult formations such as shale demand the use of functional mud system to complete a well safely and economically. The economic viability of 50/50 oil-water ratio invert emulsion which uses vegetable oil and egg yolk as a non-toxic emulsifier was evaluated. The evaluation showed less cost of mud formulation by 67% and disposal by 47.5%. This equate to saving of $55.82 per barrel of invert emulsion formulated and$28.50 per barrel disposed. The low oil-water ratio mud is viable for low fluid loss for enhanced wellbore stability and less oil retained on drilled cutting