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High temperature variation in wells used in thermal oil recovery processes, deep gas wells, offshore wells with significant riser lengths and wells completed in abnormally hot reservoirs cause compaction of formations and this induces local compression and tensile stresses in the various casing strings cemented and landed in the well. Cemented wells are under various stresses and strains in various directions which can result in significant deformations and fracture. Therefore, casing failure or damage is inevitable largely due to thermally generated strains and stresses in the casing and the surrounding formation. This research studied the effect of the non-uniform loading (poroelastic effect) on stresses and failure of casing and cement by developing a Finite Element (FE) method for the analysis of temperature-stress interaction in three dimensions (3-D) for casing, cement and formation with all its complexities using ABAQUS simulation tool. The tool was used to develop temperature distribution and thermal stresses in the casing and near wellbore formation. This enabled possible casing failure predictions and provided theoretical basis for casing thermal stress failure by coupled temperature field and thermal stress field of casing.

Casing is designed to provide well bore stability and withstand imposed loads such as external pressure, internal pressure and mechanical load due to compressive forces on casing. To ensure integrity and reliability of casings, a cost effective approach is hereby presented using finite element (FE) methods. At ordinary conditions of temperature and pressure, casing design can be achieved by the use of available grades of casing, but for HTHP wells it becomes critical to investigate the integrity and reliability of casing grades provided. Thus, numerical methods such as FE become invaluable as opposed to standard casing selection procedures. This work models stability of casing in the wellbore using a commercial industry accepted FE package – Abaqus 6.12. The model was developed using simple plane stress and plane strain elements with corresponding boundary conditions. Various mechanical properties of steel casing, concrete, surrounding rock and interfaces were modeled to mimic a full scale industry scenario. The model investigated casings under HTHP, mechanical failure criteria in terms of elasticity, plasticity of material, geometric non-linearity and compared with other existing analytical models in literature in other to validate the model. It was observed that the model becomes highly unstable under HTHP environment, hoop and radial strains in the wellbore casing increased as the temperature and pressure of the transported fluid in the wellbore increased. Areas of stress concentration in the casings can easily be observed in the model and it shows an efficient procedure for investigating the stability of casings in harsh conditions. Casings were subjected to HTHP to predict optimum configurations for different scenarios.

Casing failure has become a common occurrence especially in injection wells, which often affect development objectives of intended reservoirs. Stresses induced by injection of fluids (e.g. water, CO2, steam) in a well may affect the integrity of the casing, cement and surrounding formations. Thus, a simplified and reliable assessment of the thermal stresses induced in casings are necessary in predicting the integrity of well in complex and unconventional production activities. The injected fluid cause fracturing of the formations and this induces local compression and tensile stresses in the various casing strings landed and cemented in the well. This work presents a quick and cost effective procedure for obtaining appropriate grades of casing using finite element (FE) method. The model is developed for quick assessment of well integrity using a well-known commercial FE package- ABAQUS 6.12-1. The ABAQUS’ plane stress and plane strain elements with associated material properties were used to model the thermal stresses in casing, cement and near well bore. The effect of varying the thickness of casing was investigated and an optimum thickness corresponding to various fluid conditions was obtained. The developed model was compared to existing models in other to assess the accuracy of the model. A parametric study was conducted on the effect of casing dimensions on the stresses and strains developed in the steel casing. The results of the study showed that strains and stresses on the casing vary directly with increasing temperature and pressure of transported fluid in the wellbore casing. A strain based failure criteria was developed to aid the well design engineer in selecting appropriate casing thickness and diameter. The model presented shows a quick and reliable procedure for obtaining dimensions of casing subjected to unconventional environments.

An increasing number of gas wells worldwide produce at rates below their maximum potential due to liquid loading, which occurs when the gas velocity in the well falls below a critical value, at which point the liquid that was previously carried upward by the gas begins to fall back. The liquid accumulates down hole, where it increases the hydrostatic back-pressure on the reservoir, destabilizes the multiphase flow in the well, decreases gas production rate, in severe cases, can kill the well. There are a number of tools, techniques and processes that are currently used in the industry to mitigate the impact of liquid loading. Choosing the optimum artificial lift solution for a specific occurrence of loading in the field is a very challenging task that requires an integrated, multi-disciplinary approach to deliver the highest possible value for the asset. The objective of this paper is to develop a quantitative method which couples integrated production simulations, economic analysis and a distance-based optimization model to streamline and improve the selection of the most appropriate lifting option for given well conditions, while considering multiple factors impacting on the decision making process. The production system is modeled with a widely available commercial software package. The feasibility of using integrated production modeling in conjunction with a distance-based optimization methodology is demonstrated with two synthetic case studies representing a high-rate and a low-rate gas well. The results show that the proposed methodology can help optimize the selection of artificial lift solutions for liquid loaded gas wells.

Several techniques have been investigated to date to alleviate the detrimental effect of liquid loading in gas wells. However, relatively little is known about the theoretical and operational aspects of plunger-assisted intermittent gas lift for gas well deliquification. This study presents an analytical approach for modeling the performance plunger-assisted intermittent gas lift system using conservation equations (continuity and momentum), thermodynamic principles and material balance. Numerical examples are presented to illustrate the performance of the model using field data. A sensitivity study is then performed to assess the influence of different parameters on the performance of the plunger-assisted intermittent gas lift system.

Multiphase flow models for the oil and gas industry are required to investigate and understand the co-current or counter-current flow of different fluid phases under a wide range of pressure and temperature conditions and in several different flow configurations. To compliment this theoretical effort, experimental measurements are required to verify multiphase flow models under controlled conditions and assess their range of applicability. This is why there exists a large number of multiphase flow loops around the world. However, there are numerous varieties of multiphase flow occurrences due to differences in pressure and temperature, fluid types, flow regimes, pipe geometry, inclination and diameter, and whether the flow is steady-state or transient. Consider the example of hydrocarbon producing fields in the North Sea. Typical parameters for an oil well in the northern basins are as follows: production rate of 800–1600 cubic meters per day, tubing diameter of 0.102–0.130 meters, reservoir depth of 3000–3500 meters, oil density of 825–930 kilograms per cubic meters, gas-oil-ratio of 100 standard cubic meters per standard cubic meters and water cut up to 90%. For a gas well in the southern gas basin, the typical parameters become: initial production rate of 0.7 to over 2.8 million standard cubic meters per day, tubing diameter of 0.114–0.140 meters, reservoir depth of 2500–3500 meters and initial liquid-gas-ratio of less than 1 to over 30 standard cubic meters per million standard cubic meters. The operational pressure at the wellhead may reach up to 10 MPa and reservoir pressures can be as high as 30 MPa. Furthermore, not only do well performance values vary considerably across the world and, they also vary with time for the same field. Building a flow loop that reproduces real hydrocarbon wells, including the reservoir inertia and the complex heat transfer process taking place between the wellbore and the reservoir, is not feasible. Thus, downscaling of typical field parameters is necessary for the study of multiphase flows at laboratory conditions. This paper presents a critical review of multiphase flow loops around the world, highlighting the pros and cons of each facility with regard to reproducing and monitoring different multiphase flow situations. The authors suggest a way forward for new developments in this area.

Carbon dioxide (CO2) from energy consumption is a primary source of anthropogenic greenhouse gas. Injection of CO2 in coalbeds is a plausible method of reducing atmospheric emissions, and it can have the additional benefit of enhancing methane recovery from coal. Most previous studies have evaluated the merits of CO2 disposal in high-rank coals. The objective of this research is to determine the technical and economic feasibility of CO2 sequestration in, and enhanced coalbed methane (ECBM) recovery from, low-rank coals in the Texas Gulf Coast area. Our research included an extensive coal characterization program, deterministic and probabilistic simulation studies, and economic evaluations. We evaluated both CO2 and flue gas injection scenarios. In this study coal core samples and well transient test data were obtained for characterization of Texas low-rank coals. Simulation studies evaluated the effects of well spacing, injectant fluid composition, injection rate, and dewatering on CO2 sequestration and ECBM recovery. Probabilistic simulation of 100% CO2 injection in an 80 - acre 5-spot pattern indicate that these coals can store 1.27 to 2.25 Bcf of CO2 with an ECBM recovery of 0.48 to 0.85 Bcf. Simulation results of 50% CO2 - 50% N2 injection in the same 80-acre 5-spot pattern indicate that these coals can store 0.86 to 1.52 Bcf of CO2, with an ECBM recovery of 0.62 to 1.10 Bcf. Simulation results of flue gas injection (87% N2 - 13% CO2) indicate that these same coals can store 0.34 to 0.59 Bcf of CO2 at depths of 6,200 ft, with an ECBM recovery of 0.68 to 1.20 Bcf. Economic modeling of CO2 sequestration and ECBM recovery for 100% CO2 injection indicates predominately negative economic indicators for the reservoir depths and well spacings investigated, using natural gas prices ranging from $2 to $12 per Mscf and CO2 credits based on carbon market prices ranging from $0.05 to $1.58 per Mscf CO2 ($1.00 to $30.00 per ton CO2). Injection of flue gas (87% N2 - 13% CO2) results in better economic performance than injection of 100% CO2. Moderate increases in either gas prices or carbon credits could generate attractive economic conditions that, combined with the close proximity of many CO2 point sources near unmineable coalbeds, could generate significant CO2 sequestration and ECBM potential in Texas low-rank coals.