bluuebunny/crossref_metadata_2025 huggingface dataset:
Exploring Dispersion Effects and Crossflow Mechanisms in the Nearly Miscible Gas Drives
Authors: Hossein A. A. , Esmaiel T. E. H. , van Kruijsdijk C. P. J. W.
Published: December 2007

Miscibility is an important parameter to optimize oil recovery in the gas drives. Additionally 2-D effects such as channeling, gravity tonguing, and crossflow can impact the level of miscibility and both local displacement and sweep efficiency. The adverse fingering or channeling tendencies will be mitigated to varying degrees by crossflow effects induced by the following physical mechanisms: (i) mass diffusion, (ii) dispersive mixing, (iii) viscous forces, and (iv) gravity forces [10]. All these factors are rate and process dependent, so that the effectiveness of a nearly miscible displacement needs to be analyzed in a manner which takes quantitative account of these interacting mechanisms. When mixing between layers of fast and slow flow occurs, the composition paths occurred in one dimensional flow change, and hence the development of miscibility is altered, to some extent at least in heterogeneous flow systems where crossflow occurs. In any real miscible floods the flow will be anything other than one-dimensional, as reservoir heterogeneity and viscous instability produce faster flow in some zones than in others. Therefore better understanding of the scaling of those interactions is an important part of improved accuracy of performance predictions for reservoir scale flows. Furthermore as numerical dispersion can cloud the interpretation of the results by artificially increasing the level of mixing in the reservoir, the effects of numerical dispersion should be clearly analyzed for each fluid displacement at the beginning of simulations. This has been done by selecting both the appropriate grid details and the compositional representation to achieve a solution which is not overcome by numerical functional errors.

The objective of this study is to understand each individual key dispersion mechanisms induced by reservoir parameters. The second step is to identify the parameters that have strong influence on the displacement process. The numerical simulations of x-y and x-z cross sections are used to quantify the effects of various mixing factors and reservoir heterogeneity.
Combined Axial Tension/Compression and Internal Pressure Testing of Mini-Pipe Specimens in H2S Environment to Determine Three Dimensional (Triaxial) Stress States which Produce Crack Initiation Failure: Explanation of the New Test Fixture, Mini-Pipe Specimen, and Preliminary Test Results
Authors: Cernocky E. P. , Aaron V. D. , Paslay P. R. , Wink R. E.
Published: December 2007

The oil and gas industry is heading toward development of Extreme-HPHT wells which can expose low alloy, carbon steel production casing to shut-in pressures over 18,000 psi, 50-450°F changing temperatures, and a sour environment containing H2S, CO2, and water. These conditions represent a step increase in the severity of the service conditions acting on well casing. The completion of such wells requires a new, comprehensive understanding of the relationship between three dimensional service stresses (caused by load and pressure) and the capability of the pipe material to resist crack initiation. This step in understanding is aided by an evolution from the one-dimensional, pass/fail, NACE-A tensile test to an environmental test of a hollow pipe specimen loaded with a three dimensional stress state. The same type of test is able to calibrate the accuracy of a formula for pipe performance based on fracture propagation in a sour environment. This paper reports development of a compact (less than 2 ft x 1 ft), inexpensive test frame and hollow specimen geometry to address this testing need; and the paper reports initial results from such testing. Combined-load testing specimens in this frame provides a means to quantitatively determine the way that principal stresses in the well combine to cause (1) crack initiation and (2) crack propagation in low alloy carbon steel pipe in a sour environment. The testing is able to simulate the pipe combined loading which can occur in the well.

Part I of the paper explains the key features for the new test frame and specimens. The paper is intended to help enable the reader to build similar frames and specimens. The frame is able to passively apply axial tension or compression combined with internal pressure; internal H2S environment; and/or external H2S environment. The low cost and passive mechanism enable several frames to be run at the same time. The mini-pipe specimens are cut from the wall of coupling stock or heavy walled casing. The paper explains the specimen geometry, threading, end caps, H2S containment, and surface finish; the methodology for controlling loading of the coupon; and the low stiffness designed into the frame

Part II of the paper provides preliminary results of seventeen tests with combinations of tension, compression, and internal pressure; and internal/external H2S exposure. Additional tests are planned for 2005. The tests are intended to determine a critical combination of combined axial-pressure loading stresses, H2S corrosion exposure, and pipe material toughness which leads to crack initiation and failure in pressurized pipes. The role of the initiation failure formula is shown to be separate from a different formula for pipe failure due to crack propagation.
Evolution of Material Requirements and Products Answer For Critical Environments
Authors: Lepine E. , Orlans B. , Verdillon L.
Published: December 2007

Development of wells combining high pressure and high temperature (HPHT) containing hydrogen sulfide (H2S) has increased the need for high strength and sulfide stress cracking (SSC) resistant heavy wall tubular products.

The material requirements for these severe environments are continuously evolving. This trend is particularly evident in the evolution of HPHT well requirements, Sour Service applications and the associated testing protocols. On this basis, a precise combination of steel chemistry and heat treatment has enabled the development and qualification of C110 proprietary grade materials. This grade has been used in environments such as the North Sea, and is qualified under fit-for-purpose conditions. These products used worldwide and more particularly in the GoM (Gulf of Mexico), are suitable for sour service applications in heavy wall casing with various premium connections.

OCTG tubular products answer to key challenges such as dimensional specifications and mechanical properties. Unusual wall thickness and higher yield strength grades push back further exploration and production limits. In addition to the R&D effort, the high quality of such products is ensured thanks to a dedicated manufacturing process.
The Design of Tubing and Casing Premium Connections for HTHP Wells
Authors: Carcagno Gabriel
Published: December 2007

The design of premium connections for casing and tubing applications in HT/HP wells, especially in sour environment, require the consideration of extreme design conditions not present in common applications. The high pressures to stand and seal-both internal and external, and the limitations on steel yield strength due to sour environment provokes an increase of wall thicknesses, adding challenges to obtain simultaneously enough structural resistance, good seal response and low resistance to galling. The design of specific and very tight stress relief procedures is a key element to keep the material resistance to sour environment, when swaging or expansion required. Regarding design performance verification, it is based on the use of a combination of very refined non-linear Elastic-Plastic Finite Element Analysis, together with the testing concepts of new standard ISO 13679 / API 5C5, which expose the connection to a very demanding evaluation in terms of resistance to galling, extreme combined loading conditions –tension, compression, internal pressure, external pressure, bending, thermal cycling, and limit load.

This paper describes, through actual examples, the design process and the key elements that need to be considered in the design of a high performance premium connection for HP/HT Sour wells, from the paper to the manufacturing process, including the ways to balance the design features for optimum performance, and the different tools and evaluation methods required to validate the designs.
HPHT Completion Challenges
Authors: Zeringue Ron
Published: December 2007

The industry makes a pioneering discovery: 20,000 psi SITP, 100 ppm H2S, 10 % CO2, 400 °F flowing wellhead temperature. Now what?

Everyone wants production as soon as possible. What challenges need to be overcome? What equipment is available, and what needs to be designed and tested? How long will it take to design, build, test (and redesign, re-test), certify, and deliver? What challenges have yet to be identified? If you have a failure, can you work it over? Is there well control equipment in place?

Recent HPHT history indicates that infantile failures happen, usually caused by something that no one considered an issue. What are the hidden obstacles awaiting the first ultra HPHT completion? This paper will summarize current industry HPHT capability and more importantly, propose questions in an attempt to stimulate discussion on issues that we may be missing.
Improved Decision Making During Drilling Operations: Using a Wireline Coring System, Offshore Brazil
Authors: Shankel C. P. , Chachula R.
Published: December 2007

The Corion ™ Express coring system was used Offs coring programs. The Wireline system offers an efficient way to trip core while maintaining a large diameter core necessary to achieve high recovery rates and high quality cores. It also allows the operator to quickly decide as whether or not to simply drill ahead or to retrieve additional cores without additional trips in and out of the well. The coring/drilling assembly has been designed to either drill ahead in a conventional fashion or to core while drilling ahead.

The Corion Express cored the entire 3- ENC-2 reservoir interval and then deployed the drilling insert to TD the well without tripping the Drill String. 3 ½" cores of unconsolidated sand were recovered to surface conveyed by wire line through the ID of specialized drill pipe and BHA. At the completion of coring, and confirming the presence of the base formation, the drilling insert was deployed through the drill string and BHA via wire line, latched into place and the drilling to TD was completed.

This technology has the capability to provide the operator with a step level change in the acquisition of high quality cores in a more cost effective fashion. By eliminating trips the tool becomes very cost effective for long interval or multiple interval coring programs. The major advantage over existing technologies is the large diameter of the core head. The significance lies not only in larger diameter core capable of replacing conventional coring, but also in the fact that logging tools may be lowered through the bit and into the open well bore. The flexibility of a tool that offers coring, drilling, and open hole logging without tripping pipe can have a significant impact on exploration programs.
An Assessment of Economical and Environmental Drivers of Sour Gas Management by Injection
Authors: Abou-Sayed A. S. , Summers C. , Zaki K.
Published: December 2007

Many of the largest fields yet to be developed around the world contain oil, water, and high concentrations of sour gas. The fact that they are still undeveloped reflects the significant political and economic hurdles they have yet to overcome. Successful production of such fields will require careful management of surface resources (land, water, and power), subsurface resources (hydrocarbons), and associated streams (produced water, non-salable products, and E&P wastes). Several fields in the Caspian Sea are awaiting full development because they are burdened by the high expected cost and severe legal and economic risks associated with high hydrogen sulphide (H2S) content. Advantek International was contracted to undertake a comparative analysis of the engineering requirements, environmental impact risks, and economics for disposal of several associated streams in a Caspian field with 20% acid gas (CO2 and H2S).

Several technologies are available to the Operator for handling the acid gas after separating from the hydrocarbons, including chemical conversion to "benign" elemental components, underground sequestration (disposal), and underground injection for enhanced oil recovery (EOR). Underground sequestration of some E&P associated streams (produced water, drill cuttings slurries, and completion fluids) have been practiced for many years, as has been injection of natural gas and CO2 for EOR. Sour gas injection, however, is a relatively new technology, with a limited experience base.

This paper reviews comparative economic and risk analyses of various acid gas management options available to developing sour fields, considering the impact on recovery (including rate, ultimate total volume, engineering capacity), human health and safety risks, impacts on the environment, reputation consequences, implementation complexity, initial investment (capital and lead time), and potential regulatory restrictions (based on current North American standards, recent judicial actions, and Kyoto Protocols). The greatest opportunity for both improved value and reduced risk lies with reinjecting the acid gas for EOR. While uncertainty regarding the range of value is large, there are no risks that should be considered too severe or unmanageable to undertake this option.
Initial Results of WAG CO2 IOR Pilot Project Implementation in Croatia
Authors: Novosel D.
Published: December 2007

At the end of 2004, the remaining oil reserves in Croatian oil fields amounted to 8.5 million m3 and that together with high oil prices on the market represents a good base for the implementation of enhanced oil recovery methods.

After the conducted laboratory tests and simulation studies of the carbon dioxide injection process, the Ivanić oil field was chosen as the first candidate for the application of this EOR method. In order to rebuild the Gamma 2/4 reservoir pressure before the pilot project, injection of water started in 2001. The WAG CO2 process is being conducted through five cycles derived from simulation studies. After building pilot project facilities on the Iva-28 well location, the first cycle of carbon dioxide injection started in November 2003 and finished in May 2004. The next stage of the first cycle was the injection of water until November 2004. The second cycle of carbon dioxide injection started in November 2004, and finished in June this year. The main goal of this paper is to present two-year results of the CO2 WAG process, and on a broader level the knowledge accumulated in that period.

Analytical and synthetic methods of pilot project results give us information which has been tooled by inductive and deductive methods for improved knowledge and a higher level of intellectual capital. In the course of 5 WAG cycles on the production oil wells IVA-11 and 19, 76.500 m3 of oil will be produced. Oil production during the first cycle was 1900 m3, which is a good base for continuing further pilot project cycles (5 alternating CO2 and water injection cycles).
Improved Heavy Oil Recovery from Thin Reservoirs through Horizontal Well Placement and Intelligent Perforations
Authors: Tewari R. D. , Malik M. , Akbar Ali A. Husen , Naganathan S.
Published: December 2007

Bamboo West, a heavy oil (API Gravity 18-20) field is located in Muglad basin of south-central Sudan. Field consists of multilayered sandstone reservoirs of late cretaceous age. The reservoirs in this field are highly heterogeneous, thinly bedded, unconsolidated with high viscosity and strong aquifer support. The field is on production since July 2001 and is contributing significantly in the current 300,000 bopd production of Sudan.

Production performance of vertical wells through PCP and ESP suggests that field is facing severe problem of water coning and viscous fingering. Water cut has increased to 68 % in a span of less than 4 years causing decline in well productivity and leaving significant bypassed oil in the reservoir.

Horizontal wells were considered the best solution for improving the well productivity in this thinly bedded heavy oil field with objective for tapping the bypassed oil and delaying the water production while controlling the sand production due to low drawdown pressure and increased exposure to the reservoir.

This paper discusses about identification of bypassed oil, horizontal well placement cycle and dynamic underbalance with oriented perforation techniques that were used in Bamboo West field. A multidisciplinary approach and combination of these techniques used first time in the Middle East, Asia and Africa region resulted in the production of 1800 bopd in a horizontal well (Nearly four times of vertical well) of heavy oil from a reservoir of 0.5m thick with no water and sand production. Paper also emphasizes about different ingredients that are important for making the horizontal well successful in such fields, which can add value to the asset and results into improving the reserves and improvement in overall development strategy of the field.
Removal of Organic Nitrogen Compounds in LCO Reduce Hydrodesulfurization Severity
Authors: Yang H. , Chen J. , Ring Z.
Published: December 2007

The United States and Canada have set targets to reduce diesel sulphur from 500 to 15 ppm by the year 2006 and 2007, respectively. Better understanding the effects of feed matrix on sulphur removal by hydrodesulphurization (HDS) could guide refineries to select the right feed or feed pre-treatment options for their existing HDS units and achieve the required sulphur level at minimum cost. To this end, the influence of nitrogen compounds on the HDS activities of substituted dibenzothiophenes in light cycle oil has been studied over a NiMo/Al2O3 commercial catalyst using five light cycle oil feeds with different concentrations of organic nitrogen compounds. Experiments were conducted under conditions close to industrial HDS processes. Our work revealed that sulphur compounds could be removed under less severe reaction conditions if organic nitrogen compounds in LCO were reduced through adsorption by a silica column prior to HDS. The results also demonstrated that organic nitrogen compounds had more of a inhibition effect on sulphur removal by the hydrogenation pathway than by the hydrogenolysis pathway. Several approaches have been considered by refineries to meet the 15 ppm sulphur diesel specification, such as using more active catalysts, increasing catalyst volume, reducing cycle length and reducing the feedstock end point. The most refractory sulphur compounds such as 4 and 6 alkyl-substituted dibenzothiophenes become major reaction barriers when sulphur level has to be reduced. Since those sulphur compounds are removed predominately by the hydrogenation pathway, close attention should be paid to how to increase the hydrogenation activity. Commercialized Ni-Mo catalysts cannot meet the ultra-low sulphur requirement without increasing HDS severity. New active catalysts under development are mostly not entering the market before 2006. All these facts make the nitrogen removal by feed pre-treatment an attractive alternative to achieve the ultra-low sulphur goal.
The Phase Behavior of Athabasca Vacuum Bottoms + n-Alkane Mixtures
Authors: Zou X. , Zhang X. , Shaw J. M.
Published: December 2007

The phase behavior of Athabasca vacuum bottoms (ABVB), a 798.15+ K (525+ °C) boiling fraction comprising 32 wt. % pentane asphaltenes, + pentane mixtures is elucidated using x-ray transmission tomography. These pseudo binary mixtures are models for the development of novel heavy oil/bitumen production and refining processes. Depending on the overall composition, these mixtures are shown to exhibit three and four phase equilibria including both expected (L1L2V) and unexpected (L2L3V) phase behavior separated by a small L1L2L3V zone. These multiphase equilibria provide challenges in production environments, where miscible flooding is typically desired, but afford new opportunities for the development of separation technologies in refining. Example pressure-temperature at constant composition phase diagrams and pressure-composition at constant temperature phase diagrams, which focus on the bubble pressure region where multiphase regions arise, are presented. Limited phase equilibria data sets for ABVB + heptane, decane and dodecane are also presented so that trends for ABVB + alkane mixtures with the size of the alkane diluent can be explored. We expect these phase diagrams to provide insights to heavy oil producers and refiners in addition to providing a benchmark for testing phase behaviour models for these and related complex hydrocarbon mixtures.
New Ultra-lightweight Ultra-high Temperature Slurry Design Provided the Required Resilience for Steam Injection work in Kuwait
Authors: Kulakofsky D. , Armstrong K. , Szymanski M. , Raabe G.
Published: December 2007

As the global demand for energy increases, operators are being forced to drill in increasingly challenging environments. Drilling through highly depleted zones and weaker formations requires low-density cements that are pushing the limits of current technology. If the cement is made light enough to circulate, but cannot withstand downhole conditions the initial seal will only be temporary. If cement cannot be successfully circulated or fails to function shortly after placement, this can have a large impact on the drilling cost and can cause delays in production delivery due to the required remedial work. If damage is too severe, remedial work may not be enough to protect the integrity of the casing or effectively isolate the downhole formations resulting in a complete loss of the well.

Previously the industry has demonstrated the ability to both successfully circulate ultra-lightweight cement and to provide a cement that could withstand the 550°F steam environment similar to what is present in the Kuwait application, but never in the same well. This newly developed slurry design capable of circulating past these weak formations, maintaining its seal under these temperatures, and surviving chemical attack from moist CO2 (which is often present under steam injection conditions), is unique in the industry allowing the operator to proceed with plans to effectively produce their reservoir.

Slurry development including testing procedures and results will be presented. Discussion of well design, reasons for steam injection, the method for delivery of the slurry, and actual case histories will be provided.
Improving Hydrocarbon Production Rates through the Use of Formate Fluids - A Review
Authors: Downs J. D. , Howard S. K. , Carnegie A.
Published: December 2007

Formate fluids have unique physico-chemical properties that make them the ideal drilling and completion fluids for challenging well construction projects where extraordinary fluid performance is critical for economic success. They have been used in more than 400 wells across the world since their commercial introduction in 1993.

This paper reviews what has been published in the oilfield literature over the past 12 years about well production rates after drilling and/or completing with formate fluids. The conclusions of the review are a) the special properties of formate fluids facilitate the creation of long high-angle wells that improve reservoir access and inflow area; b) the formates tend to minimize formation damage; c) the use of formate fluids generally delivers wells with productivities that exceed expectations.

The published field case histories clearly show that formate fluids can only show their true performance potential when formulated with low levels of solids. When operators have experimented with the addition of weighting solids to formate fluids the drilling performance has been degraded and the well production rates have been unexceptional or below expectations.

Some of the information disclosed in the literature opens to question whether the use of linear core flooding is an appropriate laboratory test method for predicting the likely impact of formate fluids on well productivity.
The Stimulation Technology Research and Application in the Heavy-Oil Carbonate Reservoir of the Fracture and Cavity
Authors: Guo J. , Zhao J. , Chen L. , Li Y. , Fu Y.
Published: December 2007

The Ordovician carbonate reservoir in Taliram Basin is typical of fractured and caved reservoirs with thick oil layer, high temperature, deep zone and extra heterogeneity together with high density, high viscosity and high freezing point et al as common characteristics of crude oil. More than 80% wells have to be stimulated before economically producing. Based on the laboratory researches and plentiful field practices, the following stimulation modes are formed: the multiplayer acid-fracturing for long open-hole interval or layered acid-fracturing, height-control acid-fracturing against bottom water coining, a combination of hydraulic fracturing and acid fracturing. On the basis of drill so&g, logging data, well-recorded data and some geophysical data such as change rate of logging amplitude, cohere body and Jason reversion et al., model for well selecting and layer appraising is developed. We develop high-visco gelling acid, retarded acid based on surfactant, low friction resistance emulsified acid as well as insitu stiffening acid, with better retardancy, low leakage and low friction as the result, with which the damage near the wellbore is effectively solved and deeply penetrated acid-etched fracture is obtained. Furthermore, the 3D acid fracturing optimization design techniques for fractured and caved reservoir brought forward in this paper have accurately calculated the treatment data and fracture geometry, thus the effectiveness of acid fracturing is increased a lot. Up to the end of 2003, more than 220 times of application of acid-fracturing in Ordovician Carbonate Reservoir of Tahe Oilfield located in the northeast of Taliram Basin of China have indicated that 98.8% were effective, with average single-well incremental yield of 60t/d and the period of validity over 250 days, therefore, Tahe oilfield has increased the production about 311.8 × 104t altogether.
Underground Upgrading of Heavy Oil Using THAI—''Toe-to-Heel Air Injection''
Authors: Greaves M. , Xia T. X. , Ayasse C.
Published: December 2007

The expansion of heavy oil and bitumens production is limited by the lack of advanced upgrading facilities and technology. Surface processing, mainly by delayed coking and some hydroprocessing, is very capital intensive. This cost can be more than that for the reservoir engineering facilities. The THAI process achieves substantial upgrading of heavy crude oil directly in the reservoir, via thermal cracking and associated reaction transformations. It captures the underground upgrading because the horizontal producer well process operates via a ‘short-distance displacement mechanism’, similar to that which occurs in the SAGD process.

The results of a 3-D combustion cell test performed on Wolf Lake heavy oil are presented in the paper. Upgrading commenced as soon as the combustion front became anchored on the horizontal producer well. The produced oil viscosity was dramatically reduced, from 80,000 cSt, down to 50 cSt (average). The corresponding API gravity was increased from 10.1 to 20.4 °API (average). The quality of the produced oil was determined from a number of specific analyses, including TAN, Bromine number, SARA, and also water and gas analyses.

The first field pilot of the THAI process is to be conducted by WHITESANDS INSITU Ltd, the heavy oil division of Petrobank Energy and Resources Ltd., at Christina Lake, Alberta, Canada 1. The pilot is scheduled to start early in 2006, and if the project is successful, the new THAI technology could revolutionize heavy oil recovery and upgrading.
Hydrotreating Modeling-Helping Refiners To Face Challenges of the Future
Authors: Chen J. , Yang H. , Ring Z.
Published: December 2007

In order to help heavy oil upgraders and petroleum refineries optimize hydrotreater performance, a predictive hydrotreating process model is being developed to eventually predict the quality of the hydrotreated products under certain operating conditions. To establish this model, a number of important issues have been addressed and this paper summarizes the research results pertaining to these issues.
Water Injection in Viscous Oil Through Horizontal Well
Authors: Martini R. F. , Bonet E. J. , Schiozer D. J.
Published: December 2007

Water injection is often used as a recovery method for light oil reservoirs; however, for heavy oil reservoirs its efficiency is not so high mainly due to the unfavorable water-oil mobility ratio. For this reason, well placement is an important step of the production strategy definition because it can guarantee the economic viability of heavy-oil, deep water fields.

This work aimed to analyze the behavior of heavy oil displacement by water injection, through both experimental and numerical simulation studies. A rectangular plate filled with porous media was used; its petrophysical characteristics were determined, as well as the relative permeability and capillary pressure. Two horizontal wells were used and the laboratory test was performed in two stages: first, an oil saturation phase and then a displacement phase. Water saturation maps were generated for the two stages, in order to better analyze distortions due to friction effects in the horizontal wells.

A numerical simulation model was built to reproduce the behavior observed in the experiment and compare the friction pressure drop effects. It was further used as the basis of a hypothetical reservoir prototype, in field scale; the results from the simulations reproduced the experiment data qualitatively, however, some differences were observed. The friction pressure drop in the wellbore did not seem to affect the flow, especially according to the simulation results.
Heavy-Oil Gas Lift Using the Concentric Offset Riser (COR)
Authors: Szucs A. , Lim F.
Published: December 2007

The production of heavy oil presents a number of problems to deep water operators. A combination of high fluid density, hence hydrostatic head, and viscosity in the risers tied back to the floating production vessel limits the oil production rate. The Concentric Offset Riser (COR) offers a solution for convenient provision of riser base gas lift all in a single arrangement. The injection of gas at the riser base mixes with and lightens the oil, and hence enhances the production rate from heavy oil reservoirs.

The COR is a free standing and thermally efficient pipe-in-pipe riser system suitable for subsea developments tied back to a floating host vessel. The annular space has many potential uses, one of which is gas lift. The vertical riser is tensioned at the top with a buoyancy tank, and tied back to the production vessel with a flexible jumper. Such systems are being implemented in West Africa.

This paper describes the benefits of implementing the COR design for deepwater heavy oil developments.
Permeability of Breccia Facies in the Athabasca Oil Sands
Authors: Bharatha S. , Yee C. T. , Chan M. Y. , Lee D. G.
Published: December 2007

Breccia is a lithological facies present in the McMurray Formation of the Athabasca oil sands of northeast Alberta. It consists of mud or shale clasts embedded in clean sands. The mud content of this facies varies from 0-100% and the clasts range in size from millimetres to metres with varying degree of angularity and sorting. Breccia is common in bitumen reservoirs. From an in-situ recovery perspective, breccia can alter fluid flow and reduce the overall oil saturation due to the presence of the mud clasts. To properly characterize the reservoir flow properties, it is necessary to develop a systematic procedure to assign the vertical and horizontal permeability of breccia zones on a scale that is suitable for the numerical simulation of recovery methods such as steam-assisted gravity drainage (SAGD).

A methodology to calculate the 2-D permeability of breccia facies from core photographs and mathematical theory has been described in a previous paper. However, core photographs do not capture the three dimensional nature of the mud clasts in the breccia. In this paper, the 2-D theory is extended to 3-D by treating the mud clasts as impermeable ellipsoids. The effective permeability of breccia regions may be calculated from the permeability of the sand in which the mud clasts are embedded if the size and orientations of the clasts are known. As for the 2-D case, the results from theory are in satisfactory agreement with those from flow simulation. Using the theory specialized to the case of oblate spheroidal clasts, a procedure is developed to estimate the 3-D permeability of breccia regions, based on 2-D information from core photographs. The paper concludes with guidelines for systematic permeability assignment in the breccia zones of the oil sands as well as other similar formations.
Heavy-Oil Dilution
Authors: Argillier J. -F. , Hénaut I. , Gateau P. , Héraud J. -P. , Glénat P.
Published: December 2007

Heavy or extra heavy crude oils cannot be transported by pipeline without a prior reduction of their viscosity. This is commonly obtained by blending the oil with light hydrocarbons. In that case, the resulting viscosity of the mixture depends only on the dilution rate, and on the respective viscosities and densities of the oil and of the diluent. Classical diluent are light crudes, condensates, naphtha. Availability of the diluent and its possible recycling needs of course to be taken in account. In this work we have studied the influence of composition of the diluent on the viscosity reduction efficiency. In particular we show that the addition of a polar solvent to a solution of asphaltenes in toluene acts on the colloidal structure of the asphaltenes. The relative viscosity of the solution decreases, as well as the size of the aggregates of asphaltenes. In the same way, by mixing hydrocarbons and solvents owning polar functional groups in their molecule, it is shown that the efficiency of the dilution of heavy crude oils is enhanced. Hansen's theory can be used to screen the solvent efficiency. At constant dilution rate, the higher the polarity parameter or the hydrogen bonding parameter of the solvent, the greater the relative viscosity reduction of the diluted crude oil. Nevertheless, solvent owning high hydrogen bonding are generally more viscous than hydrocarbons. The influence of their interactions with the asphaltenes is hidden when the results are expressed in absolute viscosity. Polar solvents giving few hydrogen bonding give a significant reduction of the viscosity of the diluted crude oil. From an economical point of view, any improvement of the efficiency of the thinner could be a benefit for the process, by reducing the amount of solvent needed to get an acceptable viscosity, and therefore allowing a greater quantity of crude to be transported.
Viscous Oil Dynamics Evaluation for Better Fluid Sampling
Authors: Cañas J. A. , Low S. , Adur N. , Teixeira V.
Published: December 2007

Productivity potential evaluation in viscous reservoirs has been difficult in the past due to difficulties in native fluid sampling and in-situ dynamic formation testing evaluations. This is the result of the high oil viscosity and the unconsolidated sands in which they are usually deposited, which create limitations to natural flowing and smooth well testing / production.

There is no unique answer to the main question "how do we sample heavy oils in unconsolidated sands". However, from the experience Schlumberger has acquired during years, several modifications have been done to the wireline formation testers (WFT)1, such as the Modular Formation Tester (MDT*), and new modules have been developed which, linked to new best practices, have allowed high viscous oil sampling and in-situ formation testing. Some of the new modules and practices include, the extra large diameter (XLD) probe, dual packer with customized gravel pack screens, extra high-pressure displacement unit pump for low flow rates, advanced down hole flow analysis monitoring (DFA*) and special sampling techniques.

In this paper, we present a methodology, which integrates formation tester pressure and water-cut measurements with detailed reservoir characterization from logs to better understand the viscous oil dynamics in sandstones reservoirs in order to optimize fluid sampling.

A commercial reservoir simulator ECLIPSE* in fully implicit, black oil mode is used to simulate the multiphase flow during WFT pumping. Around the wellbore very fine grids are used, which, linked to a multi-segmented wellbore option, allows to model the clean out (contamination level versus time curve) and fluid drainage for different scenarios of oil viscosity, reservoir anisotropy, drilling fluid invasion, flow rate and WFT position relative to the top boundary.

The modeling results were validated using WFT field data with different rock and fluid properties. Some correlations were developed for field use that estimates filtrate contamination as a function of clean out time for several WFT modules.

A good understanding of the limitations and benefits of each tool under each scenario contributes to a better collaboration in the design and optimization of sampling jobs (best practice and calibration of available analytical planners for field use).
Unlocking the Potential: A North Sea Heavy-Oil Success Story
Authors: Wylde J. J. , Williams G. D. M. , Cousins R. E.
Published: December 2007

This paper gives details concerning one of the newest producing fields in the North Sea, West of Shetland development. Examples of the pre-start up design and implementation challenges are dwelt on, as well as the philosophy taken when commissioning the plant and chemical injection facilities. The majority of the paper focuses on the first 6 months of production history and the way in which the management of production techniques was performed and in particular how actual operations differed to the planned and designed specifications.

With production of a 20° API crude, significant operational challenges have been encountered with initial start up being a staged and controlled process. Details are given to the suite of production chemicals required to give complete flow assurance as well as to maintain plant integrity. The onset of water production brings with it a whole suite of different challenges with by far the most difficult being demulsification and this has been given particular attention.
The Relative Importance of Drawdown and Depletion in Sanding Wells: Predictive Models Compared With Data From the Statfjord Field MM
Authors: Hettema M. H. , Andrews J. S. , Blaasmo M. , Papamichos E.
Published: December 2007

Experience of sand production from the Statfjord field has been systemized to be able to predict the effect of drawdown and depletion on sand production. The aim of the study is to determine how reservoir pressure depletion will influence the sand production and to determine how sand production will influence the maximum liquid production rates. Most wells produce according to a maximum acceptable sand production criterion. Field data based on more than 300 maximum acceptable sand rate tests have been systemized by fitting those to an empirical criterion. For a better determination of the parameters, sand production histories of four wells have been analyzed in detail.

To understand more about the mechanisms underlying the sand production, the field results are compared with four different models. This work concludes that the behaviour of sanding wells at Statfjord can be described by a concept of two sand production regimes, one controlled by shear failure and the other controlled by rate.

Finally the empirical model is used to extrapolate the field experience to low reservoir pressures related to the planned deep depressurization. The results show that sand production will limit well production rates unacceptably for most formations and that downhole sand control is needed to secure high production rates during the late-life development of the field.
Solution Gas Flaring and Venting at Alberta Primary Crude Bitumen Operations
Authors: Ruff C.
Published: December 2007

In August 2005, the Alberta Energy and Utilities Board (EUB) published ST60B-2005: Upstream Petroleum Industry Flaring and Venting Report, which summarizes annual flaring and venting performance from all upstream sources. The report indicated that total solution gas flaring plus venting in Alberta from crude oil and crude bitumen batteries had been reduced to 729 106m3 in 2004 from the 1996 combined flare plus vent baseline volume of 1,808 106m3, a reduction of 59.7%. Of the 729 106m3 flared and vented solution gas, 248 106m3 (34.0%) was attributed to crude bitumen operations, and of this volume, 219 106m3 (88.2%) was the result of venting, with the remaining 29 106m3 (11.8%) being flared.

In September 2000, the EUB, as a member of the Flaring and Venting Project Team of the Clean Air Strategic Alliance (CASA), made a commitment to develop a venting management framework that would promote the reduction of venting from crude bitumen operations. In 2002, the resultant framework was included in EUB Draft Guide 60: Upstream Petroleum Industry Flaring, Incinerating, and Venting. Since then, encouraging reductions in venting at primary crude operations have been realized. The EUB is planning to release an updated version of Guide 60 in 2005 that will contain several enhancements designed to further promote reductions of solution gas flaring and venting.

This paper discusses the following items as they pertain to crude bitumen operations and primary crude operations in particular: Solution gas flaring and venting performance in Alberta to calendar year-end 2004Best practices respecting solution gas conservationCASA recommended enhancements to Guide 60
Development of High-Resolution Axial Flux Leakage Casing-Inspection Tools
Authors: Vogtsberger D. C. , Girrell B. , Miller J. , Spencer D.
Published: December 2007

Well casing and tubing integrity is a very important component in the safe operations of oil and gas wells in the US. To maintain safe operating conditions through out the life of a well, operators must periodically determine the integrity of the downhole well tubulars.

Historically, casing inspection data has been acquired with downhole wireline technology, and predominately with magnetic flux leakage (MFL) inspection tools. Limitations in available electronics, however, have meant that MFL logging tools have thus far been commercially available only in low-resolution configurations. Although proven to be highly robust and effective in downhole inspection applications, all low-resolution MFL instruments incorporate measurement and analysis techniques that limit their ability to precisely resolve defect geometry in all circumstances.

Baker Atlas is in the development of high resolution MFL logging instruments based on hall sensors and other improvements in the magnetic, electronic and mechanical configuration of the inspection system. From an industry survey, a set of requirements for a series of high resolution MFL logging instruments was established. A high resolution MFL instrument design program was then undertaken, incorporating magnetic finite element analysis, mechanical design and electronics design to meet the defined applications. A bench prototype device was used to acquire characterization data in a laboratory environment. The resulting axial flux leakage inspection data was then analyzed to determine the instruments basic defect detection thresholds and sensitivity to changes in defect length, width and depth. Finally, an operational field test device was used in field applications to verify operational performance of the inspection system. This paper will review the development process and outline expected benefits of the tubular inspection system.

These developments of high-resolution MFL logging instruments are intended to produce a more accurate determination of defect geometry, which will provide operators with improved data for casing integrity management.
Refining Geology With the Bit: An Innovative Approach to Well Design and Geosteering
Authors: Lee C. , Foster H.
Published: December 2007

Maximizing bitumen recovery from thermal horizontal wells requires optimal placement of the wellbore close to the bottom of the reservoir. Canadian Natural Resources Ltd. is collaborating with Halliburton to utilize logging while drilling (LWD) techniques to achieve optimal well placement in relatively thin heterogeneous reservoirs of the Clearwater Formation in its commercial cyclic steam stimulation operations in east central Alberta, Canada.

Halliburton's StrataSteer3D ® service is used both prior to, and during, drilling in real time to plan, model, and steer the horizontal well. Resistivity, and gamma ray are monitored in real-time to detect the base of the reservoir during horizontal drilling and thereby geo-steer the well one meter above the reservoir base. Real-time data are used to recalculate well plans as new surveys and petrophysical data are acquired. Data collected are integrated using DecisionSpace ® for 3D geological modeling and well planning. Geological surfaces are revised while drilling and are applied to successive wells. Log responses are also characterized and correlated to the known area geology.

This method of using the bit to steer by, and refine, the geology results in a reduction in overall drilling time by eliminating the need to intentionally ‘tag’ the bottom of the reservoir. Wellbore completion is also improved by ensuring maximum steam contact with the reservoir. The precision of vertical wellbore placement is increased thereby giving greater confidence in subsequent reservoir performance characterization.
A Method for Reservoir Management of Waterfloods
Authors: McLachlan K. , Ershaghi I.
Published: December 2007

This presentation introduces a method for continuous monitoring of water flood performance data whether it be for individual wells, group of wells, or an entire field. Efficiency of immiscible displacement using water injection depends on a number of parameters including mobility ratio, aspect ratio and the heterogeneity index. Cumulative Water Oil Ratio, here referred to as CWOR, can serve as a dimensionless parameter to assess the efficiency of a flood. For typical ranges of these controlling parameters, a simulation based study was conducted covering multiple combinations of these factors. Estimations were made of the expected ranges of CWOR's. These ranged from 1.5 to over 50. Additionally, the buildup trends of instantaneous WOR (IWOR) versus CWOR for various reservoir specific conditions were examined as a monitoring tool to gauge the efficiency of a flood versus the expected asymptotic levels. A procedure is suggested for estimation of reservoir heterogeneity index from comparisons dimensionless plots of IWOR vs. CWOR.