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Kuwait Oil Company (KOC) offshore exploration and development plans are underway to boost its production capacity to the future target rate. However, the selection of offshore field development scheme is critical due to the associated flow assurance risks, which impact project economics, safety, and sustainability. The objective of this study is to simulate and evaluate two offshore field development schemes, namely subsea multiphase flow, and platform schemes. The evaluation is based on the associated flow assurance risks, project economics, and environmental impact of each development schemes. The analysis covers simulation of each scheme, prediction of flow assurance risks, and prevention/mitigation of the risks during the entire life of the field. Results revealed that although the flow assurance risks in the subsea multiphase flow scheme are significant, it eliminates the large investment cost of platform, which improves the project economics significantly, and minimize environmental impact. Conversely, although the platform development scheme has low flow assurance risk, platform capital investment cost may impair the project economics, safety, and environmental impact. This study investigates each scheme by simulating, economically evaluating, and environmental impact assessing both schemes, to enable the right decision and selection of field development plan.
Formation damage can occur in the vicinity of the wellbore or far field in the reservoir. Organic and inorganic deposition such as asphaltene, paraffin, iron sulfide, barium sulfate and calcium carbonate are the most commonly encountered scale types of damage. Accidental interactions between the completion kill fluid after the perforation or the drilling fluid while drilling through the target zone are also major causes. The decline of well productivity is the first indication of formation damage and can be used as a determining factor of its severity. Therefore, the type of damage, the mechanisms, and controls need to be analyzed and predicted.
This paper presents a detailed and comprehensive review of formation damage including both the external and internal types and the far field and near-wellbore damage. Damage can be identified by observing changes mainly in the well productivity; however, it can be also observed using retrieved equipment such as logging tools and downhole pumps or due to the restricted entry of completion equipment such as inflow control devices (ICDs). The impact of well configuration on the formation damage and the remedy afterwards is also discussed in details.
The present study provides a solution and control criteria for the formation damage and a comprehensive mechanistic modeling is proposed. The model is applied by coupling reservoir modeling with the wellbore conservation equations through the pressure. The effect of horizontal laterals is included by developing three-phase transient equations to account for the flow rate change from toe to heel in the drain hole.
Summary High-viscosity liquid two-phase upward vertical flow in wells and risers presents a new challenge for predicting pressure gradient and liquid holdup due to the poor understanding and prediction of flow pattern. The objective of this study is to investigate the effect of liquid viscosity on two-phase flow pattern in vertical pipe flow. Further objective is to develop new/improve existing mechanistic flow-pattern transition models for high-viscosity liquid two-phase-flow vertical pipes. High-viscosity liquid flow pattern two-phase flow data were collected from open literature, against which existing flow-pattern transition models were evaluated to identify discrepancies and potential improvements. The evaluation revealed that existing flow transition models do not capture the effect of liquid viscosity, resulting in poor prediction. Therefore, two bubble flow (BL)/dispersed bubble flow (DB) pattern transitions are proposed in this study for two different ranges of liquid viscosity. The first proposed transition model modifies Brodkey's critical bubble diameter (Brodkey 1967) by including liquid viscosity, which is applicable for liquid viscosity up to 100 mPas. The second model, which is applicable for liquid viscosities above 100 mPas, proposes a new critical bubble diameter on the basis of Galileo's dimensionless number. Furthermore, the existing bubbly/intermittent flow (INT) transition model on the basis of a critical gas void fraction of 0.25 (Taitel et al. 1980) is modified to account for liquid viscosity. For the INT/annular flow (AN) transition, the Wallis transition model (Wallis 1969) was evaluated and found to be able to predict the high-viscosity liquid flow pattern data more accurately than the existing models.
Asphaltene deposition prevention, mitigation, and management remains a major challenge to the oil industry due to its complexity and current poor understanding and inadequate predictive tools. A literature review study on the asphaltene deposition revealed a lack of integrative models that link reservoir, wellbore, and surface facility to predict asphaltene deposition and take into account their effect on each other. In addition, most of the existing studies are focused on the thermodynamics aspects of asphaltene precipitation, or single-phase asphaltene deposition modeling. Therefore, it is critical to model asphaltene deposition under multiphase flow conditions to, accurately, develop prevention, mitigation, and management strategies, which depends on not only asphaltene thermodynamics, but also multiphase flow hydrodynamics and behavior. The objective of this study is to develop a robust systematic approach for predicting asphaltene deposition in production system through coupled reservoir and wellbore production model, which provides a cost-effective optimal mitigation and management strategies. The proposed work in this study integrates five models, namely reservoir asphaltene deposition model, equation-of-state (EOS) model, asphaltene thermodynamics precipitation model, mechanistic multiphase flow model, and asphaltene deposition transport model. The above-mentioned models are integrated using developed workflow platform, which enables compositional tracking throughout the entire production system. Furthermore, experimental fluid characterization data was used to tune the EOS model and the thermodynamic asphaltene precipitation models to ensure accurate phase behavior and the volumetric calculations, as well as of asphaltene and resin precipitations at any operating conditions. A field case study is used to evaluate the proposed integrated model, which indicates severe asphaltene depositions in production tubing and flowline. The proposed model predicted the thickness growth with time of asphaltene deposits on the inner tubing wall. The model results also show that local asphaltene deposition reduced tubing cross-sectional area, increasing in-situ superficial oil and gas velocities, thus increasing pressure drop. These results are critical in selecting, optimizing, and implementing asphaltene deposition mitigation and management strategies, which impacts project economics.
Pseudo-slug flow is a sub-regime of intermittent flow that is characterized by short, undeveloped, frothy chaotic slugs, with translational velocity less than the mixture velocity of the fluids. Pseudo-slug flow does not comply with the basic characteristics of conventional unit-cell slug flow where liquid blocks the entire pipe cross-sectional area, and liquid is scooped at slug front, transferred to slug body, and shed back to liquid film. The liquid in pseudo-slug body is insufficient to reach the upper part of the pipe wall, resulting in only large wave with entrained gas bubbles at the bottom part of the pseudo slug body. Consequently, a significant reduction in the gas phase flowing area above the wave is formed, which increases the local gas velocity, entraining large volume of liquid droplets in the upper part of the slug body. Therefore, the pseudo-slug body can be divided into two regions, liquid film (wave) with entrained gas bubbles at the bottom, and gas core with entrained liquid droplets. The objective of this study is to develop a plausible physical model of the experimentally observed pseudo-slug liquid holdup phenomenon and model the physical and hydrodynamic behavior using a dimensional regression modeling approach.
This paper discusses liquid and gas entrainment mechanisms within pseudo-slug body based on experimental observation. Previous experimental results show that the proposed dimensionless groups; namely, Stokes, Slippage, and Poiseuille are strongly correlated to pseudo-slug body liquid holdup experimental data and are capable of describing the experimentally observed physical behavior. A linearized regression model is developed to combine the liquid holdup proportionally in both regions of the pseudo-slug body (mentioned above) and correlate them to the experimentally measured total pseudo-slug liquid holdup using wire mesh sensor. A validation study of the proposed model with
This paper discusses a method for optimizing production facilities design for onshore/offshore wells during new field development. Optimizing the development of new oil and gas fields necessitates the use of accurate predication techniques to minimize uncertainties associated with day-to-day operational challenges related to wells, pipelines and surface facilities. It involves the use of a transient multiphase flow simulator (TMFS) for designing new oil and gas production systems to determine the feasibility of its economic development.
A synthetic offshore oil field that covers a wide range of subsurface and surface facility data is considered in this paper. 32 wells and two reservoirs are considered to evaluate the effect of varying sizes of tubing, wellhead choke, flowline, riser, and transport line. A detailed investigation of the scenario of emergency shutdowns to study its effect on the system is performed using TMFS. Other scenarios are also evaluated such as startup, depressurization, pigging, wax deposition, and hydrate formation.
This paper provides a method to minimize the cost by selecting the optimum pipelines sizes and diameters, and investigating the requirements of insulation, risk of pipeline corrosions and other related flow assurance parameters. Different facility design scenarios are considered using TMFS tool to achieve operational flexibility and eliminate associated risks. Pressure and temperature conditions are evaluated under several parametric scenarios to determine the best dimensions of the production system. This paper will also provide insight into factors affecting the flow assurance of oil and gas reservoirs.
Failure investigation of 12″(305 mm) high pressure steel welded pipe was carried out in this study using ASTM standards in all mechanical and metallurgical tests. Visual inspections was done immediately after receiving the failed pipe section. The pipe was then cut at approximately the center position of the failedwelded joint showing a circumferential crack at the joint along half of the outer surface periphery of the pipe. Tensile, hardness, chemical and microstructural analyses were performed on samples taken at different orientation of the pipe and the weld. Optical emission spectrometer were used to obtain chemical composition of samples. Microstructure testing of surfaces were prepared using grinding, polishing and etching. SEM was used to study failure at high magnification. Root cause of failure was found to be due to combination of operating conditions, oxidation cyclic stresses, and depletion of chromium in the matrix near grain boundaries, methods to reduce corrosion were discussed.
Optimizing the development of oil and gas fields necessitates the use of accurate predication techniques. The predictions should also involve minimizing the uncertainties associated with day-to-day operational challenges related to wells, pipelines and surface facilities. The choke size settings, for instance, need to be frequently adjusted to optimize production flowrates using the right techniques.
This paper provides a method to optimize the production flowrate for existing wells and to minimize the cost through finding the best cost-effective selection. Providing an insight into factors affecting the flow assurance of oil and gas reservoirs is also included. The study has been implemented by the use of nodal analysis conducted by a surface network simulation, to reach the optimum design of oil and gas production systems. The optimization of the wells can be achieved by changing tubing and flowline sizes, minimizing the skin factor, controlling the water cut, and adjusting the gas-lift injection pressure.
The Hurricane oil field that covers a wide range of subsurface and surface facility data is simulated in this paper. Seven reservoirs are considered in this study containing eleven different wells. Seven of these wells are producing naturally while the remaining four wells are gas-lifted. For each of the eleven wells, different parametric scenarios are run on the different size of the pipelines and chokes. Flow assurance study has been conducted to know the effect of severe slugging, wax deposition, and hydrate formation. Severe slugging has been predicted using a surface network simulation, while wax deposition and hydrate formation using a pressure-volume- temperature (PVT) simulation. For the artificial lift wells, as this field was mainly operated by gas lift, a new design has been implemented based on gas surface injection rate as a way to eliminate the workover operations.
Two-phase flow in vertical wells is a common occurrence in oil and gas production. High-liquid viscosity two-phase upward vertical flow in wells and risers presents a new challenge for predicting pressure gradient and liquid holdup due to the poor understanding and prediction of flow behavior, specifically flow pattern. Current two-phase flow mechanistic models were developed, validated, and tuned based on low-liquid viscosity two-phase flow data for which they show accurate flow pattern predictions. The objective of this study is to investigate the effect of liquid viscosity on two-phase flow pattern in vertical pipe flow. Further objective is to develop new/improve existing mechanistic flow-pattern-transition models for high-liquid viscosity two-phase flow in upward vertical pipe flow. High-liquid viscosity flow pattern two-phase flow data was collected from open literature, against which existing flow-pattern transition models were evaluated to identify discrepancies and potential improvements. The evaluation revealed that existing flow transitions do not capture the effect of liquid viscosity. Therefore, two bubble/dispersed bubble flow pattern transitions are proposed in this study for two different ranges of liquid viscosity. The first proposed model modifies Brodkey (1967) critical bubble agglomeration diameter by including liquid viscosity, which is applicable for liquid viscosity up to 100 mPa.s. The second model, which is applicable for liquid viscosities above 100 mPa.s proposes a new critical bubble diameter based on Galileo dimensionless number. Furthermore, the existing bubbly/intermittent flow transition model based on Taitel et al. (1980) critical gas void fraction of 0.25, is modified to account for liquid viscosity. For the intermittent/annular flow transition, Wallis (1969) was found to be accurate for high liquid viscosity two-phase flow and able to capture the high liquid viscosity data better than existing models. A validation study of the proposed transition models against high liquid viscosity data and a comparison with Barnea (1987) model revealed sensitivity to liquid viscosity and better results in predicting high viscosity liquid flow pattern data.
Lower Fars heavy oil <16 °API is considered a type of conventional heavy oil, which will be considered as priority petroleum production system for future heavy oil recovery in Kuwait. These types of oils are abundant in great amounts in Ratga field North Kuwait, yet expensive to produce due to its high viscosity hence low mobility underground. Kuwait strategy is shifting focus to these types of oils since conventional medium oil and other less-quantitative-light-oil reservoirs are continuously depleting. The study's interest is directed towards a specific type of EOR oil, which is hot dry air sequestration into Lower Fars heavy oil. This study presents novel heavy oil recovery method for 14 °API crude oil using hot dry air as well as their potential recoveries. All recoveries considered for this study are bench-scale laboratory physical experiments with horizontal (0 °), vertical (90 °), and directional (45 °) continuous air diffusion augmented with applied different thermal heat treatments.
The main objective for this research is to model recovery efficiency from this hot dry heat diffusion technique (HDAD). This technique will produce air diffusion design. This design will consider direction of blow diffusion for three possible well orientations: horizontal 0 degrees, vertical 90 degrees, and directional 45 degrees. Also, the design will consider six temperatures: 27 °C 30 °C 60 °C 70 °C 85 °C and 100 °C dry hot air diffusions. Moreover, the design will consider two diffusion velocities 74.08 km/hr and 111.12 km/hr. These velocities will determine designing the time of recovery, which is one hour, according to lab-time limitations and permissions. The main technology motivation for hot dry air diffusion (HDAD) research is finding the optimized economical EOR recovery efficiency factor that will extract most of 14 °API Lower Fars oil. The model determines the recovery potential factor in a classic, optimum and conventional economic scenario considering the energy usage to generate the hot dry air delivered to the reservoir. Also, HDAD technology usages will avoid the use of water technologies recoveries. Avoiding water technology recovery will minimize environmental impact, crude oil/ emulsions subsurface-mobility issues and costly water production management used at current steam economic challenges.