The short- and long-term volatility of oil and gas prices has a wide-ranging impact on both parties of petroleum contractual agreements, thus affecting the profitability of the project at any stage. Therefore, the government (first party) and the international oil company (second party) set the parameters of their contracts in a way that reduces the uncertainty. The effect of price fluctuations on economic indicators is investigated in this paper. The Taguchi method is used for the first time to find the best-agreement parameters, which are the “A” and “B” factors, in the standard Libyan agreement. There are four “A” components from “A1” to “A4”, and four “B” components from “B1” to “B4”. The purpose is to reduce the variability in the response variables, which are the company take (the percent of net cash flow for the international company) and average value of the second-party percent share of production (ASPS). The noise factors considered in this paper are oil, liquefied hydrocarbon byproduct (LHP), and gas prices. The method was applied to a case study of oil field development in Libya. The results showed that “A3” and “A4” were the most important control factors that affect the ASPS, while “B2” and “B3” are the most important factors affecting the company take. To obtain robust results, the most important factors to reduce variability were also determined. The effect of control parameters on the average NPV may be worth more than USD 22 MM in the 1-billion-barrel oilfield case study. The results showed that, for a given combination of “A” and “B” factors with a certain company take, the mean absolute deviation (MAD) of the NPV of the second party was reduced by 18% if the optimal combinations of the levels were used.

This paper aims to theoretically investigate and characterize the failure mechanism of hydrated bentonite plugs, when used as a sealing material in wellbores. Using the proposed theoretical models, it was determined that when hydrated bentonite plugs failed due to friction at the walls, created by internal swelling pressure or through internal shear failure, the resulting failure pressure was linear with the plug height (H), coefficient of friction or internal shear strength, and inversely proportional to plug diameter (D). On the other hand, if the friction at the walls was created by plug weight then the failure pressure was a function of H-2/D. However, in this case, the frictional strength increased parabolically with height, and, at reasonable plug heights, the frictional strength became greater than shear strength, and resulted in failure due to internal shear failure, which also made the failure pressure a function of H/D. This suggests that plug strength is usually a linear function of H/D. Moreover, the coefficient of friction and internal shear strength are dependent on final moisture content of the hydrated plug, the salinity of the hydration water, pressure, temperature and hydration time. The strength of a bentonite plug is inversely proportional the total volume by which it expands during hydration and takes in excess of 185 days to achieve this state. Plug strength decreased in saline water, although even at elevated concentrations sufficient strength remained to produce and adequate seal.From very limited data, shown here, Queensland bentonite, from the 5D zone of Amcol's Gurulmundi mine, appeared to have similar plugging strength as Wyoming bentonite.

Inhibition of smectite clay swelling by precipitation of Mg(OH) between clay layers and on the surface of clays is discussed in this paper. The precipitation was carried out using different Mg salts (MgCl 6HO, Mg(NO) 6HO Mg(SO) 8HO and NaOH as a base. The change properties after precipitation were studied by X-ray diffraction and methylene blue dye examination. The swelling tests were carried out using vial test method. It was evident from XRD that, after precipitation, bentonite resembled chlorite structure. It is noticed that the adsorption capacity of the samples increased after precipitation due to an increase in the surface area of samples. The samples precipitated with Mg(OH) with Mg:OH ratio more than 8 did not swell in the formation water and showed a more prolonged treatment effect. The Mg(OH) precipitated on the external and internal surface of bentonite. The internally precipitated Mg(OH) could be responsible for the change in the clay structure and inhibit water adsorption between layers of clay structure, while Mg(OH) precipitated on the surface of clays stops water adsorption leading to swelling inhibition. The precipitation was further carried out on mudstone sample, and swelling was observed via micromodel test.

The findings in this report indicate that bentonite is a viable method of sealing wells, wether they be coal seam gas wells, conventional oil and gas wells, water wells, or coal bores. The predominant focos of this project has been the detailed chracterization, geomechanical testing and a field trial of bentonite plugs manufactured at UQ. In the final stages of the project preliminary tests to investigate a pumpable concept were also successfully undertaken.Data previously published by Chevron indicate that plugging wells with bentonite is potentally cheaper and more reliable than plugging wells with cement slurry. Consequently, this project is ripe for commercialisation.

In coal seam gas (CSG) operations gas and associated water enter the casing-tubing annular space of wells from multiple producing intervals, forming counter-current two-phase flow patterns within the wellbore. These flow patterns, or regimes, determine the pressure profile in the wellbore, influencing flow and the production efficiency. Salts such as sodium chloride (NaCl) are abundant in the formation water, and are known to inhibit the coalescence of gas bubbles within gas-liquid flows. However, the effect of salinity on all of the flow regimes and their transitions has not previously been clarified. To investigate the influence of salinity on two-phase flows we conducted experiments in an apparatus designed to resemble a pumped CSG well in Queensland, Australia consisting of 7-in casing and 2¾-in tubing. Two-phase flow regimes (homogeneous and heterogeneous) and their transition zones (homogeneous-heterogeneous and post-heterogeneous) were induced using saline solutions of up to 11,198±142 ppm, and associated differential pressure measurements recorded for comparison with results using fresh water. Formation water produced from a Queensland CSG well was also tested. Signal processing techniques (autocorrelation, power spectral density, Shannon entropy and permutation entropy) and high-speed image analysis were applied to characterize the two-phase flow regimes. Reduced bubble coalescence resulted in higher void fractions developing within saline water at equivalent flow rates to fresh water during the homogeneous regime and homogeneous to heterogeneous transition zone, with an increase in void fraction of up to 5-6%. These flow behaviours predominantly consist of small gas bubbles and so are most affected by salinity. Once the flow rates were increased and the system transitioned to heterogeneous and post-heterogeneous flow, the impact of turbulence became increasingly dominant and the effect of salinity was less significant.

Australia is uniquely positioned globally as a major energy provider, but this comes with multiple challenges that must be overcome to realize its full potential. LNG developments that are nearing fruition are set to make Australia the largest supplier of LNG in the world. The Asian LNG market continues to be the growth market. The development of the world's first coal bed methane (coal seam gas) to LNG projects on the east coast has created a robust east coast LNG export market that complements the long term and expanding west coast LNG developments. However, in the near future this is expected to coincide with an east coast energy shortage, arising from low exploration activity, maturing fields, higher costs, the interaction of government policy, commercial decisions and activism. As a result, unique approaches to project management and community relations have been developed that are complementary to the Australian consumer's needs for reliable, affordable and cleaner energy. The east coast demand for gas is likely to trigger new development of onshore Northern Territory gas in the short term, if political opposition can be managed. In Western Australia, new approaches leverage technologies such as floating LNG, and more utilization of existing infrastructure and plant capacity to achieve lower costs. This paper outlines Australia's natural gas supply & demand and the challenges to be faced in the coming years.

This paper aims to characterise the complex flow behaviour of counter-current gas-liquid flows in concentric vertical annuli over a wide range of gas and liquid flowrates. The experiments were performed with air and water in two different annulus sizes: (a) a 100 mm hydraulic diameter annulus with a 170 mm diameter outer pipe and a 70 mm diameter inner pipe; and (b) a 19 mm hydraulic diameter annulus between 44 mm and 25 mm pipes, to investigate the effect of flow geometry on flow structure. Flow regimes were identified quantitatively by applying fast Fourier transform (FFT) on the associated pressure fluctuation signals, collected at 10 Hz and 100 Hz frequency. Video images captured at 4,000 fps with a high-speed camera were used in a visual analysis of the flow regimes to verify the FFT results. Furthermore, flow regime transitions and their underlying mechanisms were determined by their associated pressure gradient and void fractions, as well as analysis of temporal pressure signals. The commonly described slug flow regime, consisting of stable Taylor bubbles traversing the length of the channel, was not observed in the larger annulus. However, the FFT of the pressure signals indicate that unstable Taylor bubbles form as a result of bubble coalescence but collapse due to instability at the gas-liquid interface, known as Rayleigh-Taylor instability. Therefore, the apparent slug-chum flow regime was classified as a highly turbulent heterogeneous flow, developing at superficial gas velocities from 0.265 to 3.968 m/s and superficial liquid velocities from 0.004 to 0.147 m/s. Interestingly, annular flow regime did not develop in either of the tested small and large annuli. The onsets of counter-current flow limitations, or flooding were identified in the 100 mm hydraulic diameter annulus with gas flooding due to very high gas flow rates and liquid flooding due to very high liquid flow rates. The mechanism that initiates gas flooding was observed to be the formation of large waves flowing upward near the water inlet point, with counter-current flow observed below the water inlet point at the onset of gas flooding. Clarity was also provided on the concepts of flooding and zero liquid penetration for the cases of flow in a water filled channel and a falling film, and a new empirical correlation for the onset of flooding was developed.

We characterised different flow regimes and their transition through an objective and quantitative assessment of flow behaviour by applying four signal process techniques (autocorrelation, power spectral density (PSD), Shannon entropy, and permutation entropy) onto pressure signals of counter-current two-phase flows in a 170mm×70mm concentric vertical annulus. Differential pressure values were measured using a 100Hz sampling rate with 30 second sample sizes in 147 experiments at superficial gas velocities within 0.043–5.387m/s and superficial liquid velocities within 0.016–0.093m/s. Video images were also captured during all flow experiments. Using the signal analysis techniques, we could overcome the difficulties and uncertainties that accompany subjective visual observations in the characterisation and classification of flow regimes. Also, the signal analyses of the pressure signals allowed us to provide insights into the mechanisms responsible for formation of each flow regimes and their transitions.

Abstract Australia is uniquely positioned globally as a major energy provider, but this comes with multiple challenges that must be overcome to realize its full potential. LNG developments that are nearing fruition are set to make Australia the largest supplier of LNG in the world. The Asian LNG market continues to be the growth market. The development of the world's first coal bed methane (coal seam gas) to LNG projects on the east coast has created a robust east coast LNG export market, which in the near future is expected to coincide with domestic energy shortages arising from low exploration activity, maturing fields, higher costs, the interaction of government policy, commercial decisions and activism. As a result, unique approaches to project management and community relations have been developed that are complementary to the Australian consumer's needs for reliable, affordable and cleaner energy. The east coast demand for gas is likely to trigger new development of onshore Northern Territory gas in the short term, if political opposition can be managed. In Western Australia, new approaches leverage technologies such as floating LNG, and more utilization of existing infrastructure and plant capacity to achieve lower costs. This paper outlines Australia's natural gas supply & demand and the challenges to be faced in the coming years.

Two-phase slug flow is a common phenomenon observed in oil and gas wells and pipelines. Mechanistic modelling approaches used in industry for design and monitoring rely on closure relations (e.g. Taylor bubble rise velocity in a stagnant fluid) to approximate phase interactions. In this work, the phase-field lattice Boltzmann method (PFLBM) originally proposed by Fakhari et al. [4] and extended to three dimensions by Mitchell et al. [10] is employed to investigate the validity of some of these closure relations. The PFLBM solves the conservative phase-field equation to capture the interfacial dynamics while resolving the hydrodynamics through a velocity-evolution LBM. To assist with model stability at high density and viscosity ratios, a weighted-multiple-relaxation-time (WMRT) operator is incorporated in the hydrodynamic scheme. The model is first validated for Taylor bubble transport in vertical pipes at a range of Morton (Mo) and Eotvos (Eo) numbers. The effect of inclination in tubular pipes is then investigated and compared with existing correlations in the literature. The study concludes with an assessment of the Taylor bubble rise velocity in annular piping with comparison to experimental results.

A fault stability study constitutes a fundamental element of any subsurface injection project that involves faults within a storage complex, yet the transient geomechanical effects introduced due to CO2-rock chemical interactions are rarely considered. This paper presents a review of the published work investigating the potential alteration of rock properties due to short to long term CO2-host rock chemical interactions during commercial scale carbon capture and storage (CCS) operations. Furthermore, the authors of this paper are attempting to highlight the potential significance of these mechanical-chemical effect on the fault reactivation potential for a commercial scale carbon capture and storage (CCS) operation. The reactive nature between CO2 dissolved in formation water and the storage reservoir can significantly alter the hydraulic and mechanical properties of the host rock, which could in turn affect the storage potential of the target reservoir. Alteration of the host rock mineralogy due to chemical interactions with CO2 have been well studied (Farquhar et al. 2015), but little is available in the published literature on the resulting changes in rock elastic properties (i.e. Young's modulus and Poisson's ratio) due to these reactions. Some recent experimental studies have suggested significant changes in rock properties occur. When we incorporated the geomechanical effects, induced by the rock elastic property changes documented in these published cases, into both 1D analytical and 3D numerical models based fault stability analyses for a Surat Basin reservoir, we observed significant modification of the reservoir storage capacity prior to reaching fault reactivation criteria. Based on our review of the published literature and our fault stability analyses, we conclude that the chemical effects of CO2 interaction with host rock needs to be experimentally tested to confirm if these effects are significant. If yes, then these effects should constitute an integral part of the geomechanical study for any large scale CO2 injection exercise if there is a critically stressed fault as part of the storage complex.

Abstract Coal seam gas (CSG) well operators typically follow an industry rule of thumb 0.5 ft/s liquid velocity to prevent the onset of gas carryover during CSG dewatering operations. However, there is very little experimental data to validate this rule of thumb with only a publication by Sutton, Christiansen, Skinner and Wilson [1] available in the open literature. A review of more general studies on two-phase gas-water flows in vertical pipes and annuli revealed that experimental conditions, especially pipe and annuli diameters, can have a significant impact on development of two-phase flow phenomena. As such, the limited available data may not be applicable due to differences in experimental conditions. This study experimentally investigates the onset of gas carryover using an experimental setup intended specifically for the study of CSG wells. The University of Queensland Well Simulation Flow Facilities were designed to replicate as closely as possible the production zone of a typical vertical CSG well in Queensland, Australia in transparent acrylic pipes to observe two-phase flow behavior in simulated downhole conditions. The annular test section in the rig was constructed of a 7-in casing and 2¾-in tubing. Modification of the experimental setup to include a vertical separator allowed for the detection of gas carryover. Conceptual demonstrations of gas carryover were captured and have been illustrated. The experiments in this study validate the industry rule of thumb of 0.5 ft/s liquid velocity as an appropriate guideline for onset of gas carryover in a casing-tubing annulus dimension similar to a typical CSG well in Queensland.

Subsurface porous formations containing nonaqueous phase liquids (NAPLs) such as crude oils are often targets for surfactant flooding during enhanced oil recovery (EOR) or aquifer remediation processes designed to mobilize and solubilize oil. Recent studies suggested that putting surfactants into micro-emulsified state prior to injection might improve their performance. Most of these studies proved that microemulsion (ME) efficiency depends on test conditions and the proper selection of their chemical formulations and brine chemistry. However, the impact of rock characteristics on the complex fluid-rock interactions is still unclear, especially in heterogeneous rocks. The goal of this fundamental study was to examine the effect of MEs on oil displacement in three different aged rocks (Berea, Edwards, and Tensleep) and identify the test conditions in which MEs outperform surfactants. The effectiveness of surfactants and MEs was evaluated at two concentrations from different sets of spontaneous imbibition tests and petrographic analyses. Several mechanisms such as reduction of interfacial tension (IFT), oil emulsification, and wettability alteration were responsible for the improved recovery. Wettability alteration of aged cores by surfactants and MEs led to an early oil removal by spontaneous imbibition while emulsification increased the ultimate amount produced. Both additives lowered the IFT from 12 to less than 1 mN/m. However, high ME concentration was able to decrease the size of oil droplets by one order of magnitude, significantly enhancing oil mobilization in all three rocks. The solubilization capability of MEs was superior in Tensleep due to their unique ability to penetrate dolomite cements and alter their wettability.

CO2 capture and utilization caused more and more public attention because of its environmental impact. The objective of this work was to study the catalytic gasification of a sub-bituminous coal from the Powder River Basin (PRB) using a CO2 and H2O mixture as the gasifying agent. Sodium and iron, in the form of inexpensive compounds, were chosen to catalyze the coal gasification. The experiments were conducted between 700 and 900 °C in a fixed-bed laboratory gasifier under the atmospheric pressure. Results show that the added catalysts had an effect on the composition of gas products in a way different from it in pure steam gasification. Fitting models for kinetic data were examined and the results show that addition of 3 wt% Na or 3 wt% iron led to a 28.0% or a 19.5% reduction in the activation energy of the gasification reaction, respectively. The sodium and iron in the coal char were characterized and the results show that sodium is more evenly distributed than iron during gasification. Suggestions for improving the catalysts' performance in coal gasification were proposed accordingly.

Natural gases containing sour components exhibit different gas compressibility factor (Z) behavior than do sweet gases. Therefore, a new accurate method should be developed to account for these differences. Several methods are available today for calculating the Z-factor from an equation of state. However, these equations are more complex than the foregoing correlations, involving a large number of parameters, which require more complicated and longer computations. The aim of this study is to develop a simplified calculation method for a rapid estimating Z-factor for sour natural gases containing as much as 90% total acid gas. In this article, two new correlations are first presented for calculating the pseudocritical pressure and temperature of the gas mixture as a function of the gas specific gravity. Then, a simple correlation on the basis of the standard gas compressibility factor chart is introduced for a quick estimation of sweet gases’ compressibility factor as a function of reduced pressure and temperature. Finally, a new corrective term related to the mole fractions of carbon dioxide and hydrogen sulfide is developed.

The accurate prediction of two-phase gas and liquid flow regimes is important in the proper design, operation and scale-up of pressure management and fluid handling systems in a wide range of industrial processes. This paper provides a comprehensive review of 3947 published experimental data points for gas-liquid flow maps in vertical pipes and annuli, including a critical analysis of state-of-the-art measurement techniques used to identify bubble, slug, churn and annular flow regimes. We examine the critical factors of pipe geometry (diameters, deviation from vertical), fluid properties and flow conditions that affect the transition from one flow regime to another. The review surveys the theoretical models available to predict flow regime transitions, and we validate the accuracy of these models using the published experimental data. The most reliable flow regime transition models for upward co-current flows are analytically shown to be: (i) Barnea 1987 for dispersed bubble to bubble flow, (ii) Taitel et al. 1980 for bubble to slug flow, (iii) Barnea 1987 for slug to churn flow, and (iv) Mishima and Ishii 1984 for churn to annular flow regime transition. Moreover, based on the review we provide an outlook on the research needs and important developments in prediction of two-phase flow in vertical pipes including the use of computational fluid dynamics (CFD) techniques to simulate gas-liquid flows in vertical geometries.

Two types of porous media were analyzed with the intention of exploring alternative enhanced oil recovery methods. Core samples were taken from the Tensleep Formation of the Black Mountain Field in Hot Springs County, WY. The lithology is mainly sandstone and dolomite. The measured effective porosity values ranged from 13.0 to 18.0%, and permeabilities from 19 to 68 md. Production from the Tensleep and Phosphoria formations using conventional methods has resulted in a low secondary recovery factor, possibly due to high capillary forces and an oil-wet formation. Different surfactants were investigated to determine the viability of a possible enhanced oil recovery process using a spontaneous imbibition process in Amott cells. A very high enhanced recovery factor of more than 89% was achieved using a complex nano-fluid that consists of a mixture of surfactant, solvent, co-solvent and water. These recovery factors compared with 13% by brine imbibition and up to 21% using commercial surfactants. At the other end of the scale, very high porosity volcanic pumice was also subjected to the same tests. For this rock the porosity values ranged from 65 to 90% and permeabilities were 2.0–2.7 d. Secondary recovery showed values up to 81% on spontaneous imbibition and up to 91% when surfactants were employed. These experimental results indicate that pumice has favorable reservoir characteristics, but, due to its weak brittle nature, it would not be expected that it could withstand the overburden stress at any significant depth. However, it does represent a useful laboratory specimen.

Abstract The swelling of smectite clays in the interburden rock layers of coal seam gas wells results in spalling of fine particles that may negatively impact gas production through damage to the well's pump and/or the permeability of the coal layers. One of the causes of the clay swelling is the change in water chemistry at the wellbore location due to drilling fluids and the influx of produced water. The conventional technology to mitigate the swelling of smectite clays in oil and gas reservoirs is to stabilize the clay using a brine such as 4 % KCl, and although this technology is relatively low cost and initially effective the mitigation of clay swelling is temporary because K+ ions are easily washed from the clay when the well is brought into production. An alternative approach recently reported is to use nanoparticles and nanofluids to control clay swelling. In this laboratory study we evaluated the effectiveness of five commercially available nanoparticles – SiO2, Al2O3, ZnO, Fe2O3, and ZrO2 – to prevent swelling of a natural bentonite clay that was rich in sodium montmorillonite. The effectiveness of the nanoparticles to prevent clay swelling was measured with a visual swelling index method based on ASTM D5890-11 and compared to the swelling of the clay in 4 % KCl brine. In the initial nanoparticle screening tests performed in distilled water all the nanoparticles except for the ZnO exhibited some potential to mitigate the swelling of bentonite. The next stage of screening experiments was performed in model formation water solutions containing 2500 mg /L and 9000 mg/L of Na ions at pHs of 5 and 9. In the model formation water tests, the SiO2 was the most effective nanoparticle to mitigate clay swelling across the range of conditions examined. These experimental results suggest nanoparticles may be a potential solution to mitigate clay swelling and spalling in coal seam gas reservoirs as well as other types of reservoirs. Further research is required to elucidate the mechanism of swelling inhibition with SiO2 nanoparticles and to develop practical methods to deploy nanoparticles into a CSG well.