bluuebunny/crossref_metadata_2025 huggingface dataset:
Redevelopment of a Matured Multilayered Carbonate Offshore Field through High Technology Horizontal and Multilateral Wells
Authors: Kumar R. , Ramanan S. , Narasimham J. L.
Published: December 2007

Oil productivity from Mumbai High field, an offshore multilayered carbonate reservoir, increased significantly through implementation of a major redevelopment programme. High technology drilling viz. horizontal/ multilaterals for the new development wells was adopted on field scale to effectively address typical complexity of the layered carbonate reservoirs. Since the commencement of the project in 2000, around 140 new wells were drilled, mostly with horizontal and multilateral drain holes. Besides these, more than 70 sub-optimal producers were also converted as horizontal sidetracks under brown field development. The horizontal sidetracks were drilled as long drift sidetrack (LDST), LDST-ERD, short drift sidetrack (SDST) and medium radius drain hole (MRDH) type of wells through application of innovative and emerging drilling technologies with non-damaging drilling fluids, whipstocks to kick off sidetrack wells, rotary steering systems, expandable tubulars to complete horizontal sidetracks in lower layers etc. With the implementation of this project, the declining trend was fully arrested and a significant upward trend in production could be established.
Investigation of a High Temperature Organic Water Shutoff Gel: Reaction Mechanisms
Authors: Al-Muntasheri G. A. , Nasr-El-Din H. A. , Peters J. A. , Zitha P. L. J.
Published: December 2007

Water production during oil and gas recovery is a longstanding problem that is becoming critical with maturing fields worldwide. Lifting, processing, treating and re-injection of the unwanted water add to the overall oil production costs. Also, water disposal may pose environmental problems. Recent statistical studies indicate that processing unwanted water costs the oil industry nearly 40 billion dollars per year.

Polymer gels have been widely used as blocking agents for excessive water production. In this study, a copolymer of polyacrylamide tert-butyl acrylate (PAtBA) and polyacrylamide (PAM) crosslinked with polyethyleneimine (PEI) have been investigated. This PAtBA/PEI system was previously shown to be stable at temperatures up to 160°C, typical of those encountered in deep oil and gas reservoirs. However, the crosslinking mechanisms of this system at high temperatures have not been well defined.

This study examined the structural changes of PAtBA and PAM using C-13 Nuclear Magnetic Resonance (NMR) spectroscopy. Understanding these changes is a first step towards the identification of the crosslinking mechanisms of PAtBA and PAM with PEI. This will have a strong impact on the design of water shut-off treatments utilizing these systems.
An Investigation of Minimum Miscibility Pressure for CO2 - Rich Injection Gases with Pentanes-Plus Fraction
Authors: Bon J. , Sarma H. K. , Theophilos A. M.
Published: December 2007

A miscibility study was conducted to investigate the effects of the C5+ content in injection gases on Minimum Miscibility Pressure (MMP). Currently available common MMP correlations are based on data from injection gases containing no C5+ fraction. However, laboratory analyses suggest that having a small (and yet relatively significant) C5+ fraction could have a large effect on reducing the MMP to considerably below the predicted values from existing correlations. This paper aims at investigating possible benefits for miscibility and CO2 EOR flooding with impurities, particularly with C5+ fraction.

Previously, a PVT and miscibility study was conducted on a Cooper Basin (located in central Australia) reservoir fluid, including solubility-swelling and viscosity studies. Slim tube tests were performed using two injection gases – pure CO2 and a CO2-rich synthetic gas (80mol% CO2), which contained a small amount of C5+ fraction (0.3mol%). The MMP was expected to increase substantially due to the presence of a large amount of methane (15mol%). Correlations from literature predicted the MMP to be above 3433psia, but the MMP was measured to be 2880psia1. As most currently available correlations are based on injection gases with no C5+ fraction, a major contributing source to error with these correlations may have been the C5+ content of the gas.

In order to investigate the effects of the C5+ fraction in the injection gas, a series of Rising Bubble Apparatus (RBA) experiments were conducted on the reservoir fluid with three injection gases at three different temperatures to investigate the effect of C5+ in the injection gas stream.

Results indicate that the C5+ fraction does have a significant effect on the MMP that needs to be factored into current correlations when the injection gas has a C5+ content.
Optimizing Wireline Formation Evaluation in HP/HT Wells
Authors: Larson Roderick A. , Duhon Lamar L. , Benavides Simon P.
Published: December 2007

Evaluating high-pressure high-temperature (HP/HT) wells has become increasingly challenging. As the wellbore temperatures exceed the continuous operating specification of available sensors and electronic components, standard deployment and data acquisition methods are no longer sufficient. Nearly all practical methods of protecting the sensors and electronics from temperature are time constrained. Therefore it is necessary to explore all options to acquire a maximum amount of data in a finite amount of time downhole. This paper will discuss the equipment and processes necessary to provide critical formation evaluation in the formidable HP/HT environment.
Selecting Representative Laboratory Test Conditions for Fit-For-Purpose OCTG Material Evaluations
Authors: Nelson Jocelyn L. , Reddy Ramani V.
Published: December 2007

The sulfide stress cracking resistance of steel oil country tubular goods (OCTG) is commonly correlated to the hydrogen sulfide (H2S) partial pressure, calculated by multiplying the mole fraction H2S by the total system pressure. However, sour gas mixtures exhibit non-ideal behaviors at high system pressure. Neglecting these non-ideal effects causes large over-conservatism at total system pressures above 5000 psi. It is important to compensate for non-ideal gas and solution behaviors in order to select representative laboratory test environments for sour service fit-for-purpose materials evaluations.
Connections for HPHT Well Applications and Connection Leak Probability
Authors: Valigura Gloria A. , Tallin Andrew
Published: December 2007

HPHT wells bring new challenges to the well design engineer. One of these challenges is connection design and selection. Connections for HPHT wells must be high performance connections that have been fully tested to demonstrate high reliability and fitness for service.

Our objective is to discuss the impact connection design and selection have on these challenges, the reasons for using two seals and the need to test each of the seals independently to ensure an acceptable connection leak probability. Shell uses the industry test standard, ISO 13679:2002 "Petroleum and natural gas industries – Procedures for testing casing and tubing connections"(1) to qualify connections. We will discuss our method for determining reliability of a connection – a probabilistic calculator-its assumptions, and how sensitive the results are to those assumptions.
A New Method of Material Categorisation for Super-Duplex Stainless Steel Tubulars
Authors: Renton Neill , Seymour Dave , Hannah Irene , Hughson William
Published: December 2007

Following the failure of a super-duplex stainless steel (SDSS) production tubular in an HT-HP well in the Shearwater field, Shell Exploration & Production in Europe have developed a new method of categorizing SDSS material using an eddy current inspection technique. The technique is designed to identify areas of hardened material with modified microstructure on the external surface of the tube, which are believed to have contributed to the Shearwater failure. This paper describes work carried out over the last 18 months into the development of the inspection technology and appropriate assessment criteria. The assessment criteria are based on a combination of numerical cut-off's and eddy current trace signature identification, newly developed as a result of this work. The technique successfully identified all tubes of concern with a rejection rate of 0.5%.
Significant Reduction of Imperfection Depth Tolerance during Ultrasonic Inspection of Oil Country Tubular Goods
Authors: Prejean Hilton , Mason Dave , McGill Randy
Published: December 2007

This paper summarizes the results of a series of demonstrations used to evaluate the effect of various conditions on conventional automated full-length ultrasonic inspection of heavy wall tubular goods using reference indicators with depths significantly less than 5% of the specified wall thickness.
The Use of Phased Array UT Inspection of OCTG
Authors: Glascock David , Brassard Michel , Mason Dave , McGill Randy
Published: December 2007

This paper covers the use of Ultrasonic (UT) Phased Arrays for the automated full length ultrasonic inspection of tubular goods. The technology provides increased flexibility to adapt to varying defect locations, shapes and orientations.

Demanding inspection parameters can be optimized for tubulars such as those used in High Pressure/High Temperature Sour Wells.
Umm Gudair Production Plateau Extension, the Applicability of FullField Dumpflood Injection to Maintain Reservoir Pressure and Extend Production Plateau
Authors: Quttainah R. , Al-Maraghi E.
Published: December 2007

More than 40 years of production has confirmed that the UG (MO) reservoir receives very little natural pressure support in some areas. The introduction of a new Production gathering center has increased the field production 6 folds. At current reservoir conditions and production strategy, the production will stay on plateau for only 3 years. This is mainly due to the rapidly falling reservoir pressure. The remedial plan is to initiate a full field water injection project to maintain reservoir pressure.

The primary objective of this project was to extend production plateau as long as economically possible. The reservoir pressure for the field, as well as different areas within it, is declining rapidly. The most important cause of this reservoir pressure decline is the high off-take rate (compared with the aquifer influx rate) and the lack of a reservoir pressure support such as water injection. This suggests that the water injection option is needed to support the reservoir pressure and extend the oil production plateau.

In this project, many development options were considered. These options can be grouped into three main groups: water injection, infill drilling and combined development options. In the water injection option, comparisons were considered. These options are surface injection vs. dumpflooding, pattern vs. peripheral injection, injection into the oil column vs. injection into the water zone. In the drilling option, comparison between infilling and sidetracking was done. Basically, within each option there was an optimization process, which consists of many sensitivity cases. The purpose behind these many cases is to optimize each option before being combined and get better results than when used alone. For example, in the water injection option, sensitivities were run to see the impact of number and location of injectors. Also, within that case, sensitivities were run to see impact of not achieving a target injection rate. For the infill drilling option, many cases were run to optimize the number of producers. For the combined development options, sensitivities were run to determine best-combined option and to study impact of water injectivity issues.

Technical Contributions: Will demonstrate the design of a fullfield water injection scheme to maintain reservoir pressure.Will demonstrate the applicability of dumpflood to repressurize a constantly depleting reservoir.Will demonstrate a cost-effective technique to maintain reservoir pressure.
An Inflow Performance Relationship for Horizontal Gas Wells
Authors: Akhimiona N. , Wiggins M. L.
Published: December 2007

As an increasing number of horizontal gas wells are drilled, the need for a quick and reliable method to estimate the pressure-rate behavior of these wells is important to optimize well performance and make operational decisions. A reliable empirical relationship will provide engineers a technique to assess the performance of horizontal gas wells prior to undertaking extensive and often time-consuming simulation studies to model the well behavior.

This work presents an analysis of the pressure-rate performance of horizontal gas wells using a three-dimensional finite difference reservoir simulator for different reservoir and wellbore conditions. The primary objective of this work is to study the pressure-rate behavior of horizontal gas wells and develop an empirical inflow performance relationship to predict their behavior.

The study investigates a range of reservoir conditions to assess their effect on horizontal gas well behavior. Parameters studied include reservoir permeability, permeability anisotropy, gas gravity, drainage area, pay thickness and horizontal wellbore length. The obtained data is used to develop empirical inflow performance relationships (IPRs) to predict the pressure-rate behavior of gas wells. The IPRs are presented in terms of pressure, pressure-squared, and pseudopressure. The resulting IPRs provide a tool by which the petroleum engineer can quickly estimate the performance of a horizontal gas well without undertaking a time-consuming simulation study.
Integrated Reservoir Management For Life Extension of a Mature and Marginal Oilfield–Talara Basin, Peru
Authors: Yesquen S. , Carro J. L. , López L.
Published: December 2007

Oil production in Peru is based on the development of mature fields with highly complex geological and reservoir characteristics; therefore, a great amount of creativity is required to operate these old fields. This is particularly true of fields located along the north coast where the low productivity of reservoirs reduce the attractiveness of development projects.

This paper outlines the Integrated Reservoir Management Process that Petrobras started in 1996 in Block X, located in the northwest of Peru on the Talara Basin – the oldest producing basin in South America with more than 100 years of continuous production.

The results obtained through the reservoirs revitalization and rejuvenation clearly reflects on the production decline variation and are based on the following aspects: Better knowledge and description of reservoirs.Optimization of development and operational costsStrong commitment to guarantee safety and environment preservation.Reasonable use and adaptation of technological advances.Human resources management program.Establishment of smaller royalties for the government to ensure new investments.
Controlling Formation Fines at their Sources to Maintain Well Productivity
Authors: Nguyen P. D. , Weaver J. D. , Rickman R. D. , Dusterhoft R. G. , Parker M. A.
Published: December 2007

Migration of formation fines has been shown to cause production decline in many wells. Despite the availability of new downhole tools for use in well stimulation and completion, the ability to sustain desired production levels is often plagued with fines migration problems. This dilemma requires appropriate treatment to mitigate fines migration at its source. This paper describes the use of an ultra-thin tackifying agent (UTTA) for stabilizing fines in high rate producing or injecting wells. This UTTA is applied as part of an initial prepad in fracturing or gravel-packing operations, a remedial treatment, or as a post-treatment following acid fracturing or matrix acidizing treatments. The primary purpose of UTTA application is to immobilize formation fines so that they will not detach, migrate with flowing fluids, plug the pore channels, and reduce the flow path permeability.

Results of laboratory testing indicate that the UTTA system is applicable to most types of formation fines, including coals, sandstones, and carbonates. Once injected into the formation matrix or proppant pack, the UTTA forms a thin film on formation surfaces, encapsulating the fines. Capillary action helps pull the tackifier into the contact points, fixing the particulate in place without plugging the pore throat. The UTTA does not require a shut-in time after its application. The thin film tackifier does not harden, but remains flexible, enhancing the ability of a formation to withstand stress cycling and allowing the formation to handle high shear stress during high flow rates.
Application of Improved and Enhanced Oil Recovery Strategies in the Tapis Field
Authors: Wan-Mohamad W-N. , Abdullah M. A. Y. , Selamat S. , Elias M. R.
Published: December 2007

The Tapis field, located offshore peninsula Malaysia, has been producing since 1978 and about 90% of the original development estimated recoverable oil has been produced. Large gas caps remain for future development. Recovery to date has been primarily from line drive pattern waterflood. Continuous implementation of improved oil recovery (IOR) strategies has increased the recoverable reserves and production capacity for economic operation of the field. This paper describes technical studies completed at Tapis and the results of recent IOR work programs that added more than 20 million barrels of reserves. In addition, enhanced oil recovery techniques currently under evaluation for Tapis are described.

The Tapis structure is an east-west trending anticline, approximately 16 km long and 7 km wide. Initially, only the northern and eastern areas were developed from four platforms. The other areas were only developed in recent years following studies to re-assess recovery from poorer quality reservoirs and application of more cost-effective technologies to commercialize them. This led to a fifth platform that developed the western area of the field.

Recently, the southern flank with marginal reserves was developed from a sixth platform, which adopted the minimal facilities satellite platform concept. Reservoir risk for this development was mitigated by additional exploration/ delineation and development well data. The data confirmed that the reservoirs are oil-bearing and productive. This marginal development was a challenge due to reservoir quality uncertainties (extensive bioturbation), structural complexities (steep bed dips, close to a major reverse fault), and fluid contact uncertainties caused by production. Reservoir simulation study was carried out to address these uncertainties to aid development planning.

Reservoir simulation study has also identified the potential for infill drilling and workovers to further improve recovery in the eastern area. This latest simulation study was conducted using finer layers, unstructured grids, and incorporated over 25 years of history matching.

Given the advanced state of field depletion, early assessment utilizing compositional simulation model and laboratory tests are being carried out to investigate the potential for enhanced oil recovery processes. Processes under evaluation include double displacement and water alternating gas (WAG) displacement using various types of gas.
Steam-Injection Strategy and Energetics of Steam-Assisted Gravity Drainage
Authors: Gates I. D. , Kenny J. , Hernandez-Hdez I. L. , Bunio G. L.
Published: December 2007

Steam-Assisted Gravity Drainage (SAGD) is being operated by several operators in Athabasca and Cold Lake reservoirs in Central and Northern Alberta. In this process, steam, injected into a horizontal well, flows outwards, contacts and loses its latent heat to bitumen at the edge of a depletion chamber. As a consequence, the viscosity of the bitumen falls, its mobility rises, and it flows under the action of gravity towards a horizontal production well located several meters below and parallel to the injection well. In practice, the temperature difference between the injected steam and produced fluids, called the subcool, is maintained between 15 and 30°C. Despite many pilots and commercial operations, it remains unclear what the impact of subcool on the performance and thermal efficiency of SAGD especially in reservoirs with a top gas zone. The objective of this study was to define a steam chamber operating strategy that leads to optimum oil recovery for minimum cumulative steam to oil ratio in a reservoir with a top gas zone. These findings were established from extensive simulation runs that were built from a detailed geostatistically generated static reservoir model. The strategy devised uses a high initial chamber injection rate and pressure prior to chamber contact with the top gas. Subsequent to breakthrough of the chamber into the gas cap zone, the chamber injection rates are lowered to balance pressures with the top gas and avoid or at least minimize convective heat losses of steam to the top gas zone. The results are also analyzed by examining the energetics of SAGD.
Pipeline Lubrication of Heavy Oil: Experimental Investigation of Flow and Restart Problems
Authors: Peysson Y. , Bensakhria A. , Antonini G. , Argillier J. F.
Published: December 2007

Heavy oil represents a large quantity of hydrocarbon resources. Unfortunately its high viscosity makes it difficult to produce and to transport. Different solutions have been developed to transport heavy oil in pipeline like blending the crude oil by a light hydrocarbon. In this study we investigate a technique based on two-phase flow: pipeline lubrication. A thin water film is injected around the internal oil core and lead to the core-annular flow regime. Water lubricates the heavy oil and longitudinal pressure gradient is then largely reduced. An experimental study has been carried out where the influence of the water content and oil flow rate has been optimized for real heavy oil as the core of the flow. The tests were conducted in steady laminar flow at moderate flow rates. The results, obtained with annular water injection at the pipe wall, show a pressure drop reduction over than 90% as compared with the same product without lubrication. These results confirm the effectiveness of the lubricating process for heavy oil transport. Restart problems and specifically the limitation of restart pressure has been also investigated.
Post-Yield Thermal Design Basis for Slotted Liner
Authors: Dall'Acqua D. , Smith D. T. , Kaiser T. M. V.
Published: December 2007

Slotted liners used for primary heavy oil recovery support relatively minor operational loads at the depths and pressures common in Western Canada. In such applications, installation loading is the primary concern, and load limits can be defined using an elastic design basis to support running operations. In thermal operations, the installation limits need to be more stringent, because of the impact of residual stresses and deformation on the operating response. Furthermore, the high axial loads induced by confined thermal expansion can place the liner into large-scale yield, where localization resistance is virtually eliminated and a variety of deformation failure mechanisms can become manifest. A prudent design takes the deformation mechanisms into consideration, balancing the mechanical requirements for supporting thermally-induced loads against the inflow requirements to generate the final design.

Commercial Steam Assisted Gravity Drainage (SAGD) projects currently under development in Northern Alberta typically use slotted liner for both injectors and producers. Reservoir sand grain size distributions and inflow requirements require slot densities as high as possible without compromising the structural integrity of the wells. Therefore, a design assessment was required to determine the relationship between slot geometry and density, thermal and production loading, and post-yield material properties. A variety of possible failure mechanisms were considered, and failure limits in terms of these controlling parameters were evaluated. The outcome was an allowable slot density, slot geometry and post-yield material description required for the liner to operate reliably, and corresponding quality assurance programs to ensure the slots and material satisfy the requirements for reliable operation.
Leveraging a New Energy Source To Enhance Heavy-Oil and Oil-Sands Production
Authors: Geddes C. J. , Curlett H. B.
Published: December 2007

Every day, approximately 800 million cubic feet of gas is burned in the oil sands region of Alberta in the extraction and processing of heavy oil and bitumen (see Figure 1).1 The vast majority of this energy is used in the creation of steam for Cyclic and SAGD oil production processes for bitumen extraction from the oil sands. One of the main factors limiting further expansion of the oil sands and heavy oil development in the region is natural gas usage.

A dependable and predictable energy source is required for continued development of heavy oil and oil sands production in Alberta. Natural gas is currently the preferred source; however, the future availability of a natural gas supply for the region and the cost of that supply are unknown variables with significant economic ramifications. Economic justification of new projects under such conditions is, at best, challenging.

Alberta, and clearly the world, is sitting on a virtually unlimited supply of usable geothermal heat energy that would be an attractive solution to the oil sands energy source problem. The green aspects of geothermal energy are appealing for both ethical and political reasons. Of even greater importance to the bitumen producer is that geothermal energy has the potential to provide a significantly positive impact to project economics – the future availability of an energy source that is guaranteed and at a known cost.
Emulsion Stability Evaluation of SAGD Product with the IPR-CEF Technique
Authors: Beetge J. H.
Published: December 2007

The IPR-CEF technique has recently been developed as a quantitative method for emulsion stability evaluation of water-in-oil emulsions. Critical electric field (CEF) measurements, made with variation in the internal phase ratio (IPR) of oil external emulsions, can reveal more information related to the mechanism of emulsion stabilization, specifically in terms of its flocculation and coalescence behavior.

Emulsions made with bitumen from a Steam Assisted Gravity Drainage (SAGD) facility were investigated by application of the IPR-CEF technique in an explorative study to evaluate the performance of the technique. The stabilization mechanism of these emulsions was also studied to explore the effect of bitumen concentration and diluent character on emulsion stability, in terms of flocculation and coalescence behavior. An attempt was made to investigate the mechanism of destabilization by a chemical demulsifier.

It is shown that the IPR-CEF technique offers valuable insight, both in understanding the mechanism of stabilization of SAGD based emulsions as well as the mechanism of demulsification by a chemical demulsifier.
Transient-Pressure Behavior of Cold Heavy-Oil Production Wells
Authors: Liu X. , Zhao G.
Published: December 2007

The objective of this paper is to investigate the transient pressure behavior of Cold Heavy Oil Production (CHOP) wells with the consideration of wormhole configurations and foamy oil flow. Wormholes provide main conduits for foamy oil flow in the production process, and foamy oil is highly compressible owing to the dispersed and encompassed gas bubbles. This study proposes a comprehensive model to describe the transient flow of matured CHOP wells. Then, the transient pressure behavior has been extensively analyzed. The model not only provides reliable transient pressure responses of matured CHOP wells, but also offers a way to estimate the possible wormhole configurations and to understand the possible pressure drop along wormholes.
Development Status of a Metal Progressing Cavity Pump for Heavy Oil and Hot Production Wells
Authors: Beauquin J. -L. , Boireau C. , Lemay L. , Seince L.
Published: December 2007

Cold Heavy Oil Production is mainly achieved by Progressing Cavity Pumps (PCP) nowadays, thanks to its low CAPEX and OPEX and adaptability to viscous and abrasive fluids. However, for thermal recovery, standard PCP is not adapted, as the elastomer composing the stator, the heart of the pump, can't withstand fluid temperature above 160°C (320F) so far. Innovative research led to the development of an original manufacturing process of a complete metallic pump, avoiding the elastomer weakness. The use of metallic PCP is in an advanced test phase. PCM and TOTAL launched industrial validation tests early 2005 in TOTAL test bench using extra heavy crude with temperatures up to 200°C (390F), pressure up to 75 bars (1090psi) and flowrate up to 260 m3/day (1600bpd) at 350 rpm. The flowrate range will be as high as 1000 m3/day (6300bpd) with new models available later this year. The validation program includes long-time running performance tests to validate its behaviour on abrasion & gas handling. Field tests will be performed before the end of the year. This paper presents the technology and promised performances associated with metal PCP used for heavy oil cold or thermal production.
Diffusivity in Heavy Oils
Authors: Creux P. , Meyer V. , Graciaa A. , Cordelier P. R. , Franco F. , Montel F.
Published: December 2007

Molecular diffusion of gases in heavy oils is one of the most important physical parameter governing cold production processes such as solution gas drive or Vapex. Indeed, the way bubbles are able to grow by diffusion will have a direct impact on gas mobilization and consequently on oil recovery. Furthermore, the importance of this parameter is emphasized by the very low gas availability characterizing extra heavy oils.

Surprisingly, publications of experimental data concerning gas diffusivity in heavy oils are relatively rare. Furthermore, published values can vary by different orders of magnitude. This is probably due to the fact that this kind of measurement is quite tricky. Indeed gas leakages in high pressure cells could be in the same order of magnitude than gas diffusion in oil. To study very viscous oil (extra heavy oils), corresponding to very low diffusivity, it is thus necessary to carefully analyze the obtained results.

The aim of this work is to characterize experimental fickian diffusivity of methane in heavy oils using two different concepts in order to be able to validate the experimental results. In this paper we present the two different methods (thermophysics and analytical) we have settled. Experimental results clearly indicate that diffusivity in extra heavy oils is lower than usually considered for ‘conventional’ oil.

From various experimental results we also propose a first mathematical model to simulate the influence of temperature on gas diffusivity.
H2S Artificial Formation as a Result of Steam Injection for EOR: A Compositional Kinetic Approach
Authors: Lamoureux-Var V. , Lorant F.
Published: December 2007

As a result of hydrothermal stress induced by steam injection in reservoirs, heavy crudes undergo chemical transformations, called aquathermolysis, the extent of which depends at least on steam temperature, injection history and both crude and mineral matrix physicochemical properties. As heavy crudes often have high sulfur content, their hydrothermal alteration results in the formation of H2S. In order to predict artificial H2S emissions during thermal EOR, we seek to develop a geochemical model to be coupled with a 3D reservoir simulator.

This paper presents the first step of the process that consists in simulating in-situ aquathermoysis in laboratory in order to derive a 0D compositional kinetic model for H2S formation.

For that purpose, aquathermolysis experiments were performed on an Athabasca oil sand sample. The amount of H2S generated during aquathermolysis was measured for different time and temperature conditions. At the same time, sulfur distribution was quantified over crude SARA fractions (Saturates, Aromatics, Resins and Asphaltenes) and insoluble fraction (mainly mineral), before and after aquathermolysis. Experimental results were then derived to elaborate a kinetic model of H2S generation upon aquathermolysis, encompassing the chemical conversion of sulfur in SARA and insoluble fractions.
Laboratory Development and Application of a Synthetic Oil/Surfactant System for Cleanup of OB and SBM Filter Cakes
Authors: Berry S. L. , Beall B. B.
Published: December 2007

During the drilling process with OB (oil-based) and SB (synthetic-based) mud systems, mud solids form internal and external filter cake along the wellbore through a filtration process (due to filtrate leakoff to the formation). After drilling is complete, a cleanup treatment to remove the OB/SB mud filter cake is needed to minimize skin and formation damage and increase production flow area. The cleanup treatment is necessary to break down the external water-in-oil emulsion filter cake, wash the damaged zone of the wellbore, and restore the formation fluid transfer properties.

Historically, solvent- or aqueous-based systems have been widely used to remove OB and SBM filter cakes. Solvent treatments are typically very expensive and aqueous systems may cause additional formation damage by forming emulsions and/or creating water saturation in the wellbore, thereby blocking oil production.

A successful OB/SBM filter cake treatment must break the mud's interfacial rheological properties, act as a demulsifier to break the water-in-oil emulsion, and break the filter cake's bond with the wellbore wall.

A synthetic oil/surfactant-based fluid system has been developed to cleanup OB and SB mud filter cakes. This paper discusses laboratory evaluation studies of the treatment fluid's effectiveness in breaking the emulsion inside the filter cake across a wide range of mud types to reduce cake cohesion and wellbore adherence. Studies with 10 field mud compositions from several mud suppliers have been conducted to evaluate the treatment fluid's filter cake removal efficiency. Laboratory data is presented showing the physical properties of each drilling mud's filter cake before and after treatment as well as the treatment's filter cake removal efficiency. Photos of the initial and post-treatment mud filter cakes are also provided for review. Finally, the paper will discuss the possible advantages of using a synthetic oil-based cleanup system over traditional aqueous-based treatments.
Reservoir Monitoring and Characterization for Heavy-Oil Thermal Recovery
Authors: Pankaj P. , Pathak V.
Published: December 2007

Extracted post-stack seismic attributes from time-lapse 3-D seismic data have been used extensively to map steam areal conformance by using statistical analysis in the development and monitoring of follow-up processes.

A quantitative cross-calibration scheme between time-lapse seismic surveys has been developed using data normalization. It was found that a significant difference results from using a different calibration set; and that time-lapse data cross-calibration provides better, more stable and consistent results. Attributes from principal component decomposition of seismic data compensate for the redundancy of conventional seismic attributes in statistical analysis and provide better well-to-seismic ties when a full set of principal component attributes are used. Vertical steam conformance can be established through poststack inversion to provide 3-D visualization of the impact of lithologic control on steam distribution and steam migration pathway. The vertical conformance reveals that sequence architecture has a significant influence on steam migration. A sequence with high mud content tends to limit or slow both vertical and lateral migration of the steam chambers.

In pre-stack efforts, the functional relation of P- to S-wave velocities, called the mud-rock line, plays an important rule in extracting S-wave information from pre-stack data. With an optimized mud-rock line and high frequency seismic data, the inverted pseudo S-wave from AVO analysis has much higher resolution than the P-S wave data. The reservoir heterogeneity can be welldefined by fluid factor alone. The application of this technique to reservoir monitoring defines steam channels and identifies lithologic barriers within the reservoir.
Field Trials for Sonic Treatment of Natural Gas Storage Wells and Stripper Oil Wells for Well Remediation and Increased Productivity
Authors: Paulsen P. D. , Johnson D. O. , Edgar D. E. , Furness J. C.
Published: December 2007

The project team of Furness-Newburge, Inc., TechSavants, Inc. and Nicor Gas performed DOE sponsored research from 2000 through 2004 to develop a sonic tool to treat underground natural gas storage wells. One of the primary damage mechanisms for these wells is the formation of scale at the perforations or at the sand face through which the gas flows during gas injection and withdrawal. During well evaluation with backpressure tests (BPT) and multi-rate pressure transient tests (MRPTT), this blockage exhibits itself as a positive skin. The sonic treatment concept is to apply high intensity sound waves to help dissolve and break-up scale that forms at the perforations or the sand face and thereby improve gas/fluid flow.

After initial development of the prototype, the sonic tool was deployed in three separate natural gas storage wells in northern Illinois. The first deployment's purpose was to ensure that the sonic treatment did not damage the well. The second and third field deployments were used to evaluate the sonic treatment's ability to increase productivity as measured by BPT and MRPTT analyses. The second deployment, in a well with a negative skin prior to treatment, showed little or no increase in well productivity. The third deployment, in a well with measured scale damage prior to treatment, showed an increase in well productivity after sonic treatment. Specifically, the skin coefficient dropped from +2.5 to −1.3 and the absolute open flow potential increased 28% from 110 to 141 MMscf/D.

In a separate study, this sonic tool was also deployed in a stripper oil well to see if sonic stimulation could increase oil production. Two treatments six months apart were performed on a well producing 6.2 barrels per day. For oil well deployment, sonic stimulation could improve well production through both viscosity reduction and through opening up blockages in the pores. Well productivity increased 15-30% in the initial period following treatment and then gradually returned to pre-treatment levels after several weeks.
Reservoir Characterization of the Wabiskaw B in the Kirby Area, Alberta, Canada
Authors: Mathison J. E. , Mireault R. A. , Wilhelm J. K. , Alwast N. K. , Williams S. K.
Published: December 2007

An integrated geological and engineering framework of the Kirby Wabiskaw B reservoir has permitted a retrospective analysis of two steam flood pilots that failed to achieve commercial success. The analysis identified four factors that negatively impacted the pilots and which would need to be addressed prior to future steam floods. The factors are: Laterally extensive calcite cemented horizons, interbedded mudstones, pore plugging kaolinite and clay diagenesis upon contact with steam.
Innovative Completion Technology Enhances Production Assurance in Alaskan North Slope Viscous-Oil Developments
Authors: Triolo M. T. , Davis E. R. , Buck B. R. , Freyer R. , Smith L.
Published: December 2007

In the challenging North Slope operating environment, use of innovative production equipment has provided solutions to zonal isolation and packer integrity problems in viscous oil reservoirs. Operators have employed new tools and technology utilizing expandable rubber materials to manage annular fluid flow, control solids/shale production, and achieve zonal isolation in wells where high costs, shallow depths, and long step-outs create unique completion challenges. The new technology is allowing once bypassed zones to be added to existing developments, and making future developments more economically viable.

The new design approach involves installing swelling rubber packer (SRP) technology as part of the completion. This technology is based on specially designed swelling properties of rubber in crude or mineral oil based mud (MOBM) to expand and seal the annulus.

The paper describes one operator's use of as many as 17 devices in a tri-lateral horizontal undulating well to manage annular flow and minimize shale/solids production. The successful application of this technology has allowed shale interbedding to be effectively isolated behind blank pipe, thus allowing an additional zone to be added to the existing development. To date the technology has been applied to eleven wells, improving production assurance.

Another major operator on the North Slope has used the technology to isolate potentially conductive fault crossings along the lateral and inadvertent zonal crossings while kicking off from the parent bore. Multiple packers have been run in single laterals to achieve the desired isolation without noticeable effects on liner running drag. Recent density caliper data shows significantly more washout than previously envisioned, increasing the desire to manage annular flow.

Development and application of this SRP technology is detailed in the paper, including documentation of improved efficiencies as a result of its use. The paper will also discuss field operations, installation, and unique considerations associated with design and installation in viscous oil environments.
Near-Wellbore Damage Remediation in Stripper Wells
Authors: Gitman A. , Watson R.
Published: December 2007

Near-wellbore damage remediation has direct impact on the improvement of the productivity of wells. The objective of this study is to investigate the potential impact of nearwellbore damage remediation on the production of shallow oil wells penetrating the Glade sandstone, located in Warren County, PA. Given the number of shallow reservoirs in the Appalachian and mid-continent basins, understanding of the potential for productivity improvement in the Glade can give insight into the potential for improvement in reservoirs with similar pressure and production rates.

To accomplish this objective, a characterization of the reservoir was first developed using the CMG commercial simulator. History matching of the production data was used in this characterization study. The simulator was then modified using the rock and fluid properties determined during laboratory analysis of the core and fluids obtained from a well penetrating the Glade sandstone. Comparison of the results of these two studies was then used to ascertain the impact of the implementation of near-wellbore damage remediation on improving well performance. In addition an investigation of the reservoir behavior given re-pressurization was performed as an alternative to the near-wellbore damage remediation.

It was concluded that removal of the formation damage would be an inefficient method of enhancing oil recovery for this particular oil field given its low reservoir pressure. By contrast, re-pressurization of the reservoir with CH4 showed positive results on the production from the wells penetrating the Glade sandstone. It was determined that the re-pressurization of the reservoir to a pressure approaching the freshwater gradient with the near-wellbore damage eliminated, would result in the highest increase in cumulative production.
Application of Microseismic Imaging Technology in Appalachian Basin Upper Devonian Stimulation
Authors: Fontaine J. , Willis R. , Griffin L. , Paugh L. , Watson J.
Published: December 2007

Microseismic imaging technology can help in providing the answers to many previously unknown questions involving the process and results of hydraulically fracturing the sandstones in the Upper Devonian wells of the Appalachian Basin. Uncertainties surrounding fracture orientation, fracture length, fracture height, the effect of treatment size, and identification of potential fracture complexities can be reduced. Developing an understanding of fracture geometry is vital and can lead to improvements in reservoir management and development.

Every year thousands of wells are drilled and completed in the Upper Devonian sands throughout the Appalachian Basin. Nearly all of these wells are fracture stimulated in some manner. The tools available to the completion engineer in designing these treatments are limited and uncertainties regarding their efficiency and optimization often exist. Process improvement can be limited or delayed by the lag time involved in determining stimulation effectiveness based upon production results. Even then inferences must be made concerning fracture geometries based upon well testing or fracture modeling. The use of microseismic fracture imaging allows real time or near real time decisions to be made.

This paper will present a case history of the implementation and utilization of microseismic fracture imaging conducted in three multi-stage stimulation treatments in Devonian Sand tight gas wells in Pennsylvania. The created fracture geometries and their implications for future treatment design, fracture model calibration, and reservoir management will be explored.
Ultralightweight Proppants: A Field Study in the Big Sandy Field of Eastern Kentucky
Authors: Kendrick D. E. , Puskar M. P. , Schlotterbeck S. T.
Published: December 2007

Nitrogen foam stimulation treatments using Ultra Light Weight Proppant (ULWP) have been successfully pumped in new gas wells located in the historic Big Sandy Field of Eastern Kentucky. The Devonian Shale play in the Big Sandy Field may be classified as extremely low pressure and low permeability. Straight nitrogen gas stimulation treatments are used in the extreme low pressure areas. Foam fracs, some rather large by Appalachian Basin standards, have been pumped frequently in the higher pressure areas of Pike County.

Ultra light weight proppant is a manufactured proppant consists of a chemically hardened walnut hull core with multiple layers of epoxy resin coating as the outer shell. ULWP has been used on more than 100 wells in the Appalachian Basin. In March of 2004 one large gas well operator decided to experiment with ULWP and replace the standard 2,000 sack – 2,500 sack 20/40 mesh sand foam frac with a similarly sized job using only about one-tenth of the mass of ULWP. Based on well treating pressures, post-frac clean-up and AOF, and short term production data, more jobs were pumped in the same field.

This paper will detail the engineering behind the decision to select ULWP, the foam frac design, and look at post-frac production of both wells using ULWP and its offsets. Finally, the value of using ULWP will be evaluated by considering the production history and costs involved.