bluuebunny/crossref_metadata_2025 huggingface dataset:
Using Regression Analysis to Relate Safety and Environmental Outcomes to Incidence Factors
Authors: Jablonowski C. J.
Published: July 2010

This paper addresses the need for more rigorous quantitative analysis of health, safety, and environmental data. Regression analysis is proposed and demonstrated as a tool to be used within the data analysis function of an operator's safety management system. It is argued that regression analysis can provide incremental value relative to qualitative or basic statistical analysis. A case study is employed to demonstrate how specific hypotheses can be tested in a systematic way. Results from such studies can be brought to bear on operational and safety management policy decisions. As results of such studies accumulate over the long term, resources will be allocated more efficiently and new best practices will emerge.
The Impact of Rotating Control Devices on the Incidence of Blowouts: A Case Study for Onshore Texas, USA
Authors: Jablonowski C. J. , Podio A. L.
Published: July 2010

Rotating control devices (RCD's) are used to provide a closed circulating system. Conventional wisdom suggests that drilling with RCD's improves kick detection and thus fewer blowouts should occur when this equipment and related practices are deployed. Some insurers require RCD's based in part on this perception. However, there is no published analysis that demonstrates a definitive link between the use of RCD's and the incidence of blowouts. In this paper, the authors use regression analysis to test for such a link. The authors find consistent statistical evidence, across a variety of regression models and variable specifications, that the use of RCD's decreases the incidence of blowouts. Future investigations could incorporate additional RCD usage data and perform a definitive benefit/cost analysis, test hypotheses about other potential benefits of RCD's (e.g. preventing drilling problems, increasing general drilling efficiency), and examine performance in other regions (US, international).
Techniques for the Study of Foamed Cement Rheology
Authors: Olowolagba Kolawole , Brenneis Chad
Published: July 2010

This paper presents methods and laboratory equipment that enable a more accurate assessment of foamed cement used to provide zonal isolation in oil and gas wells. The rotating cup and rotor viscometer commonly used to evaluate foamed cement rheology can introduce a high degree of error. Such errors can lead to the conclusion that low-quality ("quality" defined as the percent of foam in the slurry) cement foams have lower viscosities than their base fluids; such conclusions have been reported by other research organizations.

The following attributes of the "bob and sleeve" conventional rotational viscometer are contrasted to those of a three-dimensional (3D) design, referred to as the Fann Yield Stress Adapter (FYSA). Bob/sleeve can exhibit particle or bubble separation. The FYSA provides 3D mixing to maintain a homogeneous mixture of bubbles or particles.Bob/sleeve produces "wall slip," a common problem with two-phase fluids. The FYSA minimizes wall slip.Low rev/min of the bob/sleeve may not create sufficient stress to ensure velocity profile distribution in the bob/sleeve cup, resulting in significant errors. The FYSA provides 3D volume averaging shear-stress/shear-rate regimes.

A key feature of the FYSA viscometer is that it directly measures the yield point (YP) of a fluid; therefore, it does not rely on statistical regression of shear stress vs. shear rate data. It also measures shear stress vs. shear rate for a variety of complex fluids.

The rheology of foamed cement has a direct impact on the hydraulic properties of the slurry. The advantages of applying foamed cement are Increased wall shear stress for better displacement of drilling mud from the annulus and removal of filter cake from the wellbore wallsImproved fluid-loss controlPrevention of gas migration and water influx during the critical gel-strength periodReduced slurry density for protection of weak formations

This paper presents rheology-testing results using the FYSA and contrasts FYSA results with those obtained using the bob/sleeve method.
GEO Information Portal for E&P Enterprises
Authors: Sur S.
Published: July 2010

Effective reporting and readily available analytics play a vital role in the growth of any organisation. With the rise of automation and IT in business over the last few decades, these critical business requirements are addressed though multiple and often complex applications. As a result, today's workforce deals with several significantly complex applications in their daily operations.

This paper discusses the specific business needs of E&P organizations and advances in IT systems that can address these requirements. We note that even as these vital applications cover critical E&P business needs, the inherent complexity in maintaining, administering and using these applications effectively requires users to devote significant effort in managing these applications. We propose a simplistic approach of introducing a common GIS layer for extracting information from these disparate systems. This paper discusses our approach to fulfilling the information needs of most users, by mining information from various transactional and static systems without getting trained in using the myriad contemporary systems. We further discuss the basic building blocks and the complexities of realizing such an approach and how the solution can be further extended for the entire enterprise.
The Effect of Temperature and Oil Viscosity Reduction on Water Imbibition of Diatomite
Authors: Vega B. , Kovscek A. R.
Published: July 2010

Previous studies of imbibition into diatomite reservoir core as a function of temperature have revealed a systematic increase in spontaneous water imbibition leading to increased oil recovery. Forced water imbibition resulted in a trend of possibly decreasing residual oil saturation as temperature increased. These tests, however, were not conducted in a fashion that allows a simple quantification of the fraction of recovery associated with wettability change and that associated with oil and water phase viscosity reduction. The objective of this work is to delineate the relative impacts on core-scale oil recovery due to oil viscosity reduction as compared to wettability evolution during thermal recovery of light-oil from diatomite. Water imbibition tests were conducted with core samples from the exact same depth within a diatomaceous reservoir. The experiments included spontaneous counter-current water imbibition followed by forced co-current water imbibition to residual oil saturation. All tests were isothermal and carried out at temperatures ranging from 45 to 230 °C (113 °F - 446 °F). Non-wetting phases were a light diatomite crude oil and mineral oils viscosity-matched to the crude oil for each test temperature. The wetting phase was synthetic formation brine. Core samples were subject to different pre-test cleaning procedures aimed to preserve or alter the initial wettability of the sample. A core with preserved wettability was used with crude oil as the non-wetting phase. The other core was cleaned and used with the corresponding matched viscosity mineral oil. Increasing temperature resulted in a trend of increased spontaneous and forced oil recovery and lower residual oil saturation for both samples. Wettability shifts with temperature were more pronounced and systematic in the preserved wettability system. The cleaned system displayed lesser changes in wettability at all test temperatures as verified by experimental measurements of the Amott index.
The Effect of Spent Acid on Carbonate Rock Wettability
Authors: Saneifar M. , Fahes M. M. , Hosein R. L. , Hassna B. O. , Hill A. D.
Published: July 2010

This is an experimental study aimed at improving the recovery of spent acid in carbonate gas reservoirs. When acidizing, the spent acid penetrates deeper into the formation beyond the stimulated zone. The spent acid needs to be removed in order to restore the permeability to gas and enhance well performance. One of the most important factors that control spent acid recovery is rock wettability. In this study, we investigate the changes in the wettability of carbonate rocks when invaded by spent acid experimentally. These changes in the wettability are due to the various additives that are added to the acid treatment.

In this paper, we explain quantitatively the effect of wettability on spent acid recovery and we present experimental results on the effect of spent acid on carbonate rock wettability.

Our results show that carbonate rocks are not strongly water-wet; spent acid (HCl) by itself does not change wettability of the rock; some commonly used additives can change the wettability of the rock either towards stronger water-wetting or less water-wetting.

To the best of our knowledge, there is no published data on the effect of spent acid on rock wettability and how that relates to the rate of recovery and its ultimate value.
Successful Application of CO2 Tracer Technology for Surveillance of Gas Lifted Wells
Authors: Shnaib Fathi , Nadar Manickam S. , Sreekumar M. P. , Ponnuvel K.. , Peacock Larry
Published: July 2010

Well surveillance is a key component of production optimization cycle of the gas lifted assets. Even though monitoring of the surface well parameters can give some clues on the downhole gas lift system performance of oil wells, Flowing (pressure and temperature) Gradient Surveys (FGS) in most cases is still required to check the health of the downhole gas lift system and troubleshoot the downhole inefficiencies of well gas lift operations. The FGS has certain level of risk as it involves running electronic memory gauges on wireline in the well at flowing conditions.

An emerging technology using CO2 tracer was implemented as a pilot project in eleven gas lifted wells offshore fields Dubai. The results show that this method is very effective for the quick and reliable determination of lift gas entry points in the well. The method can detect the operating lift depth, detect multiple points of injection and even detect tubing leaks.

It is true that the downhole pressure and temperature data cannot be obtained from tracer surveys. Nevertheless, the technology can be used as an alternate tool to FGS for the following advantages: Minimum equipment hook-up and no need to shut-in or choke the well, means no production loss.Less equipment required for the survey, reduces logistics issues especially in offshore locations.No wireline tools introduced into the wellbore, eliminate well intervention riskSuitable for wells where a FGS is not possible due to well slugging, significantly deviated or with downhole obstruction.Possible to run tracer survey on 3-4 wells on a day if the wells are located at the same platform.

This paper will describe the objectives of the pilot project, the well candidate selection criteria, details of the execution of the survey and interpretation of the results. Practical suggestions for getting the best results from such surveys will also be provided.
Simulation Investigation of Solvent Co-Injection in Vapor and Liquid Phase to Reduce Shale Barrier Impact on SAGD Performance
Authors: Li Weiqiang , Mamora Daulat D.
Published: July 2010

It is well known that shale barriers significantly reduce steam-assisted gravity drainage (SAGD) performance at Athabasca field. An extensive 2D simulation study shows that the flow resistance at the end of shale barriers and the extra heat absorbed by the residual water inside the unproductive shale barrier are the main reasons for the shale barrier effects. Long continuous shale barriers located vertically above or near the wellbore delay production performance significantly.

We investigated potential strategies, including solvent co-injection, top injector application, or a combination of both, to reduce the shale barrier impacts. Solvent in the vapor phase can pass though the narrow flow path at the end of a shale barrier. Meanwhile, as the phase condenses from vapor to liquid, solvent efficiently reduces the flow resistance of the shale barrier. Liquid solvent coinjection can accelerate the near-wellbore flow and reduce the residual oil saturation at the wellbore vicinity. Coinjecting a multicomponent solvent can flush out the oil at different areas with different drainage mechanisms from vaporized and liquid components. Additional injector application at the top of the reservoir results only marginal improvement.
Quantifying the Fate of Hydrate Inhibitor in an HPHT Gas Condensate Subsea Tieback
Authors: Wylde Jonathan J
Published: July 2010

This paper is about an HPHT subsea tieback to a gas-condensate platform. Gas and fluids from three wells are routed through individual in-field flow lines and gather at a subsea manifold several miles from the platform. The fluids pass from the manifold through a pipe-in-pipe pipeline back to the platform.

Industrial methylated spirit (IMS) was the hydrate control chemical selected for the tieback and was used to inhibit the pipeline on a "cold start" after depressurization. There was very little data on the phase-partitioning of IMS, and quantities could end up at the oil terminal where they have a serious effect on processing and product quality.

This paper summarizes the management of using large quantities of IMS (30 m3) to cold start this subsea field. Results from a series of injection trials at the oil terminal have been summarized and show how partitioning of IMS occurs. Further, the paper explains how this proved crucial in risk assessing the impact and use of IMS on the platform. The data has been used to improve the model (CPA equation of state and HYSYS) data sets and details of this have also been included. Extensive sampling exercises performed offshore, when injecting and processing IMS (necessary in order to meet export waiver requirements), are added and lead to details of phase-partitioning behavior through the platform process plant.

Such considerations are rarely made, nor lengths taken to understand the exact partitioning and fate of a chemical when injected offshore, as well as arrival at the terminal. The implications in this instance were significant and therefore the exercise was necessary. The results show that exact quantification is very elusive and that relying on models and standard principles can be misleading and potentially damaging.
Biodiesel as Surfactant Additive in Steam Assisted Recovery of Heavy-Oil and Bitumen
Authors: Babadagli T. , Ozum B.
Published: July 2010

Use of additives to improve the efficiency of thermal heavy-oil and bitumen recovery processes has been studied extensively over the decades. Two common types of additives used in thermal applications, mainly steam assisted recovery, are solvents and surfactants. Commercial use of solvents have setbacks due to their high costs and retrieval difficulties. Cost and stability of the surfactants under reservoir operating temperature and pressure are the major concerns. We propose the use of biodiesels such as fatty acids methyl esters as a surfactant additive reducing heavy oil/bitumen-water interfacial tension in steam assisted recovery processes. Advantages of using biodiesel as a surfactant additive are that biodiesel is chemically stable under the operating pressure and temperature of the reservoir, it causes no harm on bitumen quality and release water chemistry and its use is economically feasible.

We have conducted a series of steam assisted bitumen recovery experiments to clarify the additional recovery potential and efficiency improvement capacity of biodiesel. High pressure steam at 1.8 MPa pressure, 205 °C was used in these tests at a 900 g/h feed rate. The porous media used was a normal grade oil sands ore obtained from a surface mine operation in northern Alberta, Canada. Oil sands ore was packed in a basket and placed in a high pressure cell. Bitumen recovery experiments were performed by spraying canola oil fatty acid methyl ester on oil sands ore at a 2 g/kg-bitumen dosage. These tests show that bitumen recovery efficiency increases over 40%. In another series of tests, tall oil fatty acids methyl ester was injected into a high pressure steam line at a 7.4 g-biodiesel/kg-steam dosage. Because of the solubility of biodiesel in bitumen, the effect of biodiesel on bitumen recovery could not be accurately concluded. Vapor pressure measurements performed on canola oil and tall oil derived biodiesel samples suggest that saturation compositions of biodiesel in steam at 1.8 MPa pressure and 205 °C are at least one order of magnitude higher than the requested biodiesel dosages. Further tests are planned by reducing biodiesel dosages to about 1 g and 0.5 g-biodiesel/kilogram-steam and by monitoring the solubility of biodiesel in bitumen.
Reconfiguring a California Platform for Offshore Crude Dehydration and Water Disposal via Injection
Authors: Frankiewicz Ted , Van Nostrand Bob , Manning Bob
Published: July 2010

Venoco Inc. operates Platform Holly off the California coast near Goleta. To reduce operating costs and GHG emissions, Venoco undertook a program to reconfigure the platform so that oil could be dehydrated offshore and produced water injected into wells directly from the platform. In this paper, the reconfiguration of the platform is described, starting with the production header. The service of several vessels was changed. The production separators were upgraded to provide initial 3-phase separation and allow wet oil to be dehydrated in a new electrostatic treater. Three test separators were removed, an acid surge drum was converted first to a water skimmer and then converted to a test separator, and an oil surge vessel was converted to a water surge vessel/oil skimmer. State-of-the-art internals were utilized in all vessels to improve both performance and capacity. Three PD water injection pumps were installed and three wells were converted to water injection service.

A laser-scan was performed in order to generate a 3D model of the existing platform and to develop the design for the new piping. The 3D model provided guidance for the actual installation of the new treater and identified spatial conflicts. The model facilitated both demolition of old piping and the efficient installation of new piping with a minimum amount of rework and shut-down time. All newly installed systems are in successful operation.
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

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

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

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

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

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

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

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

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

In-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

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

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

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.
Parameterization Techniques to Improve Mass Conservation and Data Assimilation for Ensemble Kalman Filter
Authors: Chen Yan , Oliver Dean S.
Published: July 2010

The ensemble Kalman filter (EnKF) is an attractive method for assisted or automatic history matching. In particular, it has been shown to be possible to efficiently match many types of data by adjusting many types of reservoir model variables, including gridblock permeabilities and porosities, facies locations, relative permeability curves, fault transmissibilities, and initial fluid contacts. At each analysis step of EnKF, model and state variables are updated to honor the production history and prior knowledge of the reservoir description using a correction that is constructed from a linear combination of the forward models. Because the update in the ensemble Kalman filter is linear and variables may be adjusted beyond their plausible range in which case the updated values are sometimes truncated, mass conservation may be violated in the updated models.

Proper selection of the model and state variables to be updated in EnKF is critically important for achieving good data match, retaining geological realism of the updated ensemble and satisfying nonlinear constraints that may apply. In this paper, we discuss parameterization techniques for these three different purposes. We revisit the updating formulation of EnKF and investigate the constraint on the weighting coefficients at the analysis step. We show that by reparameterization of the state vector, nonlinear constraints such as conservation of mass or volume, can be satisfied without complicating the updating process. The ensemble approximation of the covariance tends to be strongly corrupted by noise when the true correlation is small. Localization can regularize the ensemble-based estimate and reduce the detrimental effects of the spurious correlation, but also eliminate the effect of true correlations whose magnitude in individual gridblocks is small, but whose cumulative effect may be large. Appropriate parameterization in addition to localization could better constrain the solution of the inverse problem. Finally, the choice of model variables may also depend on observations that are available. Including model variables that are highly sensitive to certain types of data provides improved data match and more realistic updates.

A large scale reservoir model is used to illustrate these parameterization techniques. By using these techniques multiple realistic history matched models were obtained that provide reliable basis for accessing uncertainty and for design of reservoir management strategy.
Production Logging Case Studies: What Can We Say about the Well, in Addition to the down Hole Flow-profile?
Authors: Eissa Moustafa , Joshi Sameer , AlTajar Firas , Sobeih Mohamed , Alhussini Osama , Alsafadi Ghassan
Published: July 2010

Historically the main reason for running production logs (PLT) is to obtain the down hole flow profile, which is needed either for reservoir monitoring or to decide the proper remedial action in production wells.

This emphasis on calculating the down hole flow profile with the spinner & hold up tools tends to reduce the focus on the interpretation of the other production logging sensors that are normally recorded in the production logging string (such as Gamma Ray, Pressure, and Temperature). Therefore the authors would like to stress in this paper on the importance of these additional sensors and how much extra information can be obtained through the proper interpretation of these sensors.

In this paper we present seven cases that address the importance of interpreting the other sensors:➢Case # 1: Gamma Ray (GR) interpretation that helped to detect the presence of radioactive material in the hydrocarbon and understand the relation between the chemical diverters that were used during acid stimulation and the accumulation of the radioactive materials in the well bore during the shut-in conditions➢Case # 2: Qualitative interpretation of the spinner data response can help to understand the presence/nature of solids and/or viscous fluid and its relation to the performance of unproductive perforations➢Case # 3: Down hole fluid density that was computed from pressure data was used to detect the source of potential surface water production. This helped to design a successful water shut-off job that was performed later.➢Case # 4: Using pressure data to get the pressure, permeability, and skin in multi layer wells➢Case # 5: Caliper comparison to confirm the impact of acid stimulation on borehole shape.➢Case # 6: Gas Hold up and pressure measurements were used to verify the oil bubble point pressure value.➢Case # 7: Comparison of pressure measurements between surveys to understand horizontal well production profile behavior

Based on this work we would like to introduce an integrated/practical workflow for production logging interpretation that honors data from all the acquired sensors.