bluuebunny/crossref_metadata_2025_split huggingface dataset:
Successful Application of LDHI and Paraffin Inhibitor Provides a Step Change in Flow Assurance Management in a Subsea Network in the Gulf of Mexico
Authors: Allan K. J. , Wylde J. J. , Slayer J. L. , Abbate M. 
Published: July 2010

Abstract
A subsea infrastructure in the Gulf of Mexico was experiencing flow assurance challenges due to both hydrate and paraffin formation.
Dry tree wells flowed through individual subsea flowlines to a host processing facility. The condensate had a paraffin content of wt%. Paraffin control chemicals were being deployed with limited success as separator samples contained large amounts of paraffinic solids.
Pour point work showed the incumbent chemical injection had very little effect. A new product was developed to reduce the pour point to create a transportable slurry of production fluids. Cold finger experiments yielded excellent inhibition and confirmed the poor performance of the incumbent product.
Field application yielded impressive results with a clear step change in performance. Field measurements showed that deposition was unlikely to be occurring in the flow line. Pour point was also much more suppressed and paraffin content in samples was not apparent.
Hydrate formation on the same complex was occurring in a separate remote satellite well that was produced through a 10 mile subsea flowline. Daily shut downs to depressurize the flowline to remove hydrates were required. The major challenge was to reduce the daily incumbent hydrate inhibitor demand into the flowline and prevent any depressurization operations.
Modeling and process compatibility testing led to the recommendation that injection of an alternative LDHI product. Use of the chemical did not cause any fluid separation or foaming issues nor interfere with any other platform chemical applications or processes.
The correct chemical formulation and optimization creating a cost saving in reduced operations and chemical overhead for the operator. Significant value savings were created due to no lost production as shut downs were no longer required.
This paper gives a detailed description of the flow assurance root cause failure analysis, the experimental work to develop new products and results of the field applications.
A New Diagnostic Tool for Performance Evaluation of Heavy Oil Waterfloods: Case Study of Western Canadian Heavy Oil Reservoirs
Authors: Ahmadloo F. , Asghari K. , Renouf G. 
Published: July 2010

Abstract
Waterflooding is traditionally considered an unfavorable recovery method in heavy oil reservoirs. Despite this common belief, there have been very successful reported cases of heavy oil waterfloods in western Canada, with recovery factors over 40%. On this basis, a comprehensive statistical study was conducted to determine the effects of various reservoir and operational parameters on the performance of waterfloods in these reservoirs. In this study, a database of 120 operational and reservoir parameters for 177 waterfloods in Alberta and Saskatchewan was developed and analyzed.
Statistical analysis of collected database and 15 different performance indices based on the studied injection-production history was conducted using partial least squares technique. This study revealed and ranked the significance of operational parameters on performance of heavy oil waterfloods. This analysis also provided a ranking of various operational and reservoir parameters on performance of waterfloods which were successfully used for dimension reduction of input parameters. In the next step, an artificial neural network technique was applied to develop performance predictive models based on the 38 parameters selected after dimension reduction. Error analysis of the developed neural network models showed an average relative error of 10% deviation from measured performance indices using the collected production and injection histories of the studied waterfloods. This paper provides details of the successful application of the partial least squares approach and the artificial neural network for developing a diagnostic tool for evaluating and predicting the performance of waterfloods in heavy oil reservoirs based on more than 50 years of heavy oil waterflooding in western Canada. The tool developed in this study is able to predict the performance of waterfloods using the 38 easily obtainable operational and reservoir parameters.
Modeling Thermal Effects on Wellbore Stability
Authors: Nguyen D. , Miska S. , Yu M. , Saasen A. 
Published: July 2010

Abstract
Field evidence indicates that the thermal regime in wellbore considerably affects the wellbore stability in directional and horizontal wells. However, the temperature effects have not been investigated thoroughly in existing literature, and the effects of drilling fluid flow and various heat sources on the behavior of formation temperature profiles during different operations are often neglected. The affected formation temperature in the vicinity of the wellbore could result in different formation rock behaviors and consequent wellbore stability problems. This study is conducted to examine the effect of temperature on the stability of the near wellbore region, taking into account the heat transfer between formation and flowing drilling fluid with the consideration of mechanical friction and associated heat sources.
A new model is proposed that is applicable to directional and horizontal wells. The model incorporates thermal effects due to the drag forces created from the contacts between drillpipe and casing/formation during drilling and tripping operations. It is then utilized in a number of configurations of directional wells to study temperature profiles behaviors and their effects on wellbore stability. It is observed that the drilling fluid temperature is noticeably under-predicted by existing literature, and in some cases it can easily exceed the geothermal formation temperature if mechanical friction is taken into account. The formation temperature profile near the borehole region is also found to be considerably affected when wellbore heat transfer is considered, as opposed to the constant wall temperature approach in existing literature. These differences alternate the temperature induced stresses and consequently change the mud weight window for wellbore stability prediction.
The proposed model and the results of this study are very useful for more accurate analyses of wellbore stability problems with a more detailed look into the effects of temperature. They can be used to enhance predictions of thermal regime in the wellbore at the design stage of well development or mud weight selection during drilling operation, thereby, avoiding potential drilling fluid/drillstring overheating and wellbore stability problems.
Use of Fuzzy Logic for Predicting Two-Phase Inflow Performance Relationship of Horizontal Oil Wells
Authors: Ebrahimi M. , Sajedian A. 
Published: July 2010

Abstract
A straight line equation is generally used to estimate well inflow performance above bubble-point pressure. However, when the pressure drops below the bubble-point pressure, the trend deviates from that of the simple straight line relationship. Although some analytical methods can accurately represent the horizontal well IPR behavior above bubble point pressure, only empirical correlations are available for IPR modeling of two-phase reservoirs and hence some deviations from actual data are often observed.
Artificial intelligence techniques such as neural networks, fuzzy logic, and genetic algorithms are increasingly powerful and reliable tools for petroleum engineers to analyze and interpret different areas of oil and gas industry. In this paper, two neuro-fuzzy models, including Local Linear Neuro-Fuzzy Model (LLNFM) and Adaptive Neuro Fuzzy Inference System (ANFIS) have been compared with Multi-Layer Perceptron (MLP) and empirical correlations to predict the inflow performance of horizontal oil wells experiencing two phase flow.
Several reservoir models have been simulated with different bottomhole pressures. The models contained a wide range of absolute and relative permeabilities, PVT data, and horizontal well lengths. The necessary training data have been obtained from 80% of simulation results, covering a wide range of fluid and rock properties. The other 20% are used for error checking and performance testing. The results show that the Local Linear Neuro-Fuzzy Model gives the smallest error for unseen data, when compared to other intelligent models and empirical correlations.
Potential Industry Applications Using Gas Hydrate Technology
Authors: Rajnauth J. , Barrufet M. , Falcone G. 
Published: July 2010

Abstract
Over the past decade, gas hydrates have stimulated significant interest and triggered fundamental research. Primarily, the focus has been on hydrate blockage in pipelines, and on naturally occurring gas hydrates. However, gas hydrates can be useful in many different ways that can be pertinent to our industry, thanks to their unique structural packing where only certain molecules can enter the gas hydrate cavities. Among the several potential uses of gas hydrate technology are gas separation, transportation and storage of natural gas, desalination, and carbon dioxide disposal. In particular, it is possible to (i) separate the heavier components (pentane and higher) from natural gas, and (ii) capture, store and transport natural gas.
This paper proposes a workflow for capturing, storing and transporting gas in the hydrate form, particularly for situations where there are infrastructural constraints such as lack of pipelines. These applications of gas hydrate technology can have potential benefits to the oil and gas industry.
Reaction of Hydrochloric Acid with Filter Cake Created by Mn3O4 Water-Based Drilling Fluids
Authors: Al Moajil A. M. , Nasr-El-Din H. A. 
Published: July 2010

Abstract
Use of high HCl concentrations to dissolve Mn3O4-based filter cake will result in corrosive environment and release of poisonous chlorine gas (i.e., strong oxidizer). Thus, removal of deposits formed at the wellbore because of drilling fluids becomes more challenging when dealing with additives (e.g., Mn3O4) that involve complex interactions with the cleaning fluids, especially at high temperatures.
We studied the reaction of HCl with Mn3O4 particles as a function of time. Additionally, we investigated the release of chlorine gas up to reaction temperature of 284°F and 15 wt% HCl. Several techniques and instruments were employed in this study. Solubility of filter cake was examined using a HPHT filter press. GC/MS technique was used for chlorine gas analysis, atomic absorption were used to measure manganese concentrations, and to analyze solids remained after reaction we used x-ray diffraction.
Solubility of filter cake using 10 wt% HCl and temperature of 250°F was 78 wt% (no mixing during the reaction). At 190°F, high concentration of HCl (10 wt%) showed complete solubility of Mn3O4 particles while, 1 and 4 wt% HCl showed ∼70 wt% solubility. Chlorine gas was not dissociated using 4 wt% HCl at 190°F. At 284°F, 5 wt% HCl was enough to release chlorine gas. Therefore, HCl concentrations lower than 5 wt% are recommended and will dissolve most of Mn3O4. The following reaction agrees with the experimental results of 1 and 4 wt% HCl at 190°F: Mn3O4+4HCl⇌2MnCl2+MnO2+2H2O
Effect of Elasticity During Viscoelastic Polymer Flooding: A Possible Mechanism of Increasing the Sweep Efficiency
Authors: Urbissinova Tolkynay S. , Trivedi Japan , Kuru Ergun 
Published: July 2010

Abstract
It has been long believed that the viscoelasticity of polymer solution improves the displacement efficiency in polymer flood operations, but the individual effect of elasticity has not been distilled for a single viscoelastic polymer. In this study, the effect of elasticity of polymer-based fluids on the sweep efficiency is investigated by injecting two polymer solutions with similar shear viscosity but significantly different elastic characteristics.
Blends of various grades of polyethylene oxide (PEO) with similar average molecular weight and different molecular weight distribution (MWD) were prepared by dissolving in deionized water. The polymer solutions exhibited identical shear viscosity but different elasticity. A series of experiments were performed by injecting the polymer solutions in a special core holder designed to simulate radial flow through a sandpack, which was saturated with mineral oil. Injection was done through a perforated injection line located at the center of the cell and fluids were produced through two production lines located at the periphery. The experiments were conducted within a shear rate range of field applications. Since both polymer solutions had similar viscosity behavior but different elastic properties, it was possible to see the effect of elasticity on the displacement efficiency alone.
Results of the polymer flooding experiments indicated that the sweep efficiency of a polymeric fluid could be effectively improved by adjusting the MWD of polymer solution at constant shear viscosity and concentration of the polymer. The polymer solution with higher elasticity exhibited considerably higher resistance to flow through porous media than the solution with lower elasticity resulting into higher displacement efficiency and lower residual oil saturation.
Sand on Demand: An Approach to Improving Productivity in Horizontal Wells under Heavy Oil Primary Production - Part II
Authors: Diaz Brigida Meza , Sawatzky Ron , Kuru Ergun 
Published: July 2010

Abstract
The cold production recovery process is successful in vertical wells in western Canada. In this process, large amounts of sand are produced on a continuing basis along with heavy oil. Attempts at cold production in horizontal wells have not been particularly successful. When sand production has been generated in horizontal wells, these wells have tended to become plugged with sand.
This paper presents the results of experiments performed to assess the feasibility of applying cold heavy oil production with horizontal wells using less aggressive (i.e., managed) sand production strategies. Specifically, the effects of slot size, confining stress, fluid velocity and sand grain sorting on sand production were investigated.
The results indicate that slot size selection is critical for establishing "sand on demand". From the experiments, a correlation between slot size and controlled sand production was found for well sorted sands. This correlation should allow for the specification of appropriate slot sizes for target reservoirs containing well sorted sands.
In the experiments, when flow rates resulted in low but persistent sand production, channels and/or elliptical dilated zones were created that greatly enhanced the effective permeability near the slot. This observation suggests that producing at low and steady sand cuts for a long period of time might bring two benefits: a way to transport the sand out of the well without causing plugging, and the creation of high permeability channels or zones that can improve production from the reservoir.
To summarize, if the appropriate slot size was combined with the right draw down rates, controlled sand production could be achieved with attendant significant increases in permeability. This suggests that substantially increased oil production rates could be achieved from horizontal wells if sand production rates could be maintained at low but persistent levels.
Determination of Reaction Rate of In-situ Gelled Acids with Calcite Using The Rotating Disk Apparatus
Authors: Rabie A. I. , Gomaa A. M. , Nasr-El-Din H. A. 
Published: July 2010

AbstractIn-situ gelled acids have been used extensively in matrix and acid fracturing for acid diversion, reducing the leak-off rate, and retarding the acid reaction for deep acid penetration. Although literature review shows that previous studies investigated the rate of dissolution of polymer-based acid, none has addressed in details the cross-linked polymer systems. Therefore, the aim of this work was to study the mass transport and the reaction rate kinetics of the reaction of HCl in-situ gelled acid and carbonate rocks.The reaction rate of 5 wt% in-situ gelled acid was measured using the rotating disk apparatus. Rock samples of 1.5 in. diameter and 1 in. length were utilized. The rate of reaction of in-situ gelled acid was investigated at different temperatures (150, 200, and 250°F) using different rock types (Austin Chalk, Edward limestone, and Pink Dessert limestone) at rotational speeds (100–1800) rpm. Calcium concentration was measured in the collected samples and was used to determine the acid reaction rate.Experimental results showed that the reaction rate is mass transfer limited up to a rotational speed of 1000 rpm and a surface reaction limited above this value. The diffusion coefficient of 5 wt% HCl in in-situ gelled acid was determined at 150°F and reported for such system for the first time. A power law kinetic model was used to determine the rate kinetics parameters. The reaction activation energy and the rate constant at 150, 200, and 250°F were reported. Effect of Fe+3 (cross-linker) on the reaction rate was studied and was found to decrease the dissolution rate of Pink Dessert limestone by a factor of two in a comparison with gelled acid with the same HCl concentration.
Transient Behavior and Analysis of Non-Darcy Flow in Porous and Fractured Reservoirs According to the Barree and Conway Model
Authors: Al-Otaibi Ajab , Yu-Shu Wu 
Published: July 2010

Abstract
This study introduces the usage of the Barree and Conway flow model in well testing pressure-transient applications for a single-phase non-Darcy flow in porous and fractured reservoirs. The non-Darcy flow behavior is handled using a three-dimensional, general purpose reservoir simulator. This numerical model incorporates non-Darcy flow effect according to the Barree and Conway flow model and the developed numerical model is capable of simulating all near wellbore effects, such as the wellbore storage and skin effects, coupled with the non-Darcy flow behavior. In addition, a steady-state non-Darcy radial flow solution is derived analytically according to the Barree and Conway model. The numerical simulation results are verified with the analytical solution.
The numerical model is used to model and interpret the radial flow pressure-transient responses for both pressure buildup and drawdown well tests in porous and fractured reservoirs. In simulating pressure drawdown tests with the non-Darcy flow effects according to Barree and Conway model and assuming no skin and wellbore storage effects, the permeability, estimated using the standard straight-line analysis, is an apparent permeability and not the Darcy's constant permeability. The estimated permeability ranges from the minimum permeability and to less than the Darcy's permeability. Thus in pressure drawdown tests the standard straight-line analysis techniques underestimate the Darcy's permeability when non-Darcy flow behavior exists. A pressure buildup test, following non-Darcy flow drawdown tests, may be good for determining Darcy's permeability values using standard straight-line analysis when non-Darcy flow effect is insignificant. The Barree and Conway non-Darcy flow model parameters may not be directly estimated from the pressure-transient well tests with a simple graphic approach. However, they can be estimated by a matching process, based on non-linear optimization algorithm incorporated into the developed numerical model. The type curves generated by the numerical model are provided to demonstrate a methodology for modeling single phase transient non-Darcy flow behavior in porous and fractured rocks. The developed numerical model in this study is used to interpret and match actual pressure drawdown and buildup well tests from wells of high production rates in Kuwait.
Reservoir Simulation Leads to Determination of Location of Remaining Oil and Successful Drilling in the Guapo Thermal Scheme, Trinidad
Authors: Jupiter C. R. 
Published: July 2010

Abstract
Currently, one-third of the heavy oil production in Trinidad and Tobago comes from the land areas; where steam- flooding has been the preferred method of oil recovery. Guapo Thermal Scheme is such a heavy oil reservoir. However even after thirty [30] years of steaming oil recovery is only about twenty (20) percent as a result of low sweep efficiency, steam override, by-passed oil and low reservoir energy.
A well-known analytical model for thermal oil recovery processes, which determined the volume of the steamed zone, was used previously for predictions but this was upgraded to a fully explicit three dimensional model, which tracked the movement of reservoir fluids over time from inception of the steam-flood. This dynamic model was efficiently prepared using modern, state-of-the-art computers and modern simulation software. The simulated results showed that oil, water and steam banks developed and these propagated through the system in 3 dimensions. This paper shows how reservoir simulation led to the determination of the location of remaining oil and successful drilling in the Guapo Thermal Scheme, Trinidad.
Guapo Thermal Area is situated along the south west coast of Trinidad, West Indies. See Fig. 1. Steam flooding commenced in 1980. Wells were "huff and puff" initially. In 1990, the wells in the area of focus of this paper, Fault block F15BK5, experienced problems of: low steam injection, damaged casing, low fluid levels damaged liner and plugged perforations and coupled with low oil prices at that time resulted in steam injection being discontinued. Past production figures and response maps showed that the former injectors were not in communication with some off-takes suggesting an alternate faulting system. This fact was supported by a new 2D seismic / geological interpretation by C. Bhagirath and T. Andrews 2006. The study showed that the area lies within a composite incised-valley system with predominant prograding clinoforms that are elongated in a NE-direction. Reservoir simulation of this complex area led to the determination of location of remaining oil in Fault Block, F15BK5. The simulation results, which showed present day oil saturations were used in the selection, prediction and successful drilling of two [2] wells in the Guapo Thermal Scheme, Trinidad.
Failure Prediction for Rod Pump Artificial Lift Systems
Authors: Liu Y. , Yao K. , Liu S. , Raghavendra C. S. , Lenz T. L. , Olabinjo L. , Seren B. , Seddighrad S. , Dinesh Babu C. G. 
Published: July 2010

Abstract
Well failures in oil field assets lead to production loss and can greatly increase the operational expense. Predicting well failures before they occur can dramatically improve performance, such as by adjusting operating parameters to forestall failures or by scheduling maintenance to reduce unplanned repairs and to minimize downtime. This paper presents failure prediction framework and algorithms for rod pump artificial lift systems. It adapts state-of-the-art data mining approaches to learn patterns of dynamical pre-failure and normal well time series records, and to use these patterns to make failure predictions. Also, we develop a semi-supervised learning technique, called "random peek", in order to adjust the training process to cover more feature space and to overcome the bias caused by limited training samples. The data set from this paper is taken from a real-world asset using rod pump artificial lift systems. The results show that the failure prediction framework is capable of capturing future rod pump and tubing failures.