bluuebunny/crossref_metadata_2025 huggingface dataset:
Effect of Variable Injection Rate on Falloff and Injectivity Tests
Authors: Hachlaf Houari , Tiab Djebbar , Escobar Freddy H.
Published: December 2007

Numerous full field water-flooding projects are currently under way throughout the world to improve recovery. In many large oil fields water injection is initiated during the early stages of reservoir development. Exploratory wells are tested for injectivity, and injectors are tested during the field operation. As in production tests, it is quite difficult, if not impossible, to maintain a constant rate during an injection test. Any small variation in the injection rate, if not accounted for, may lead to considerable error in the calculated results. In some falloff tests, the pressure at the wellhead drops below the atmospheric pressure. When this occurs, the tubing becomes partially empty, leading to a change in the wellbore storage coefficient. A falloff of long duration is not suitable because the injection is stopped which is uneconomic.

In 1963, the two-rate flow test method was introduced. This was designed to eliminate the disadvantages of buildups and drawdowns. The disadvantage of the two-rate flow test is that the flow rate during the second flow period must be constant which leads to considerable errors in the results. To eliminate some of these difficulties, it was proposed a modification consisting of following the second rate with a rate increase. However it still required constant-rate flow. Another technique using a plot of Pwf vs log ([t+∆t)/∆t]+q2/q1log∆t to relate to system transmissibility was also introduced. This had a lacking on accuracy which was corrected later on by other study. Another researcher removed the constant rate requirement during the second flow period. Thus the test is easier to run and any fluctuation in rate is accounted for in the calculations. To overcome the problems encountered when using drawdown type curves to analyze buildup test, a technique was developed to account for the dependence of the producing time especially when the producing period is short or the flow rate is variating. This method was extended to include analysis of data from two-rate tests and multiple rate tests.

Multi-rate injection pressure test should be designed to avoid most of the above problems. In this paper, new relationships for a multi-rate injection pressure test in a non-unit mobility ratio system were developed. The pressure derivative was introduced to analyze such a pressure transient tests. Estimation of reservoir parameters was performed by the application of the Tiab’s Direct Synthesis Technique, which uses exact analytical solutions to obtain reservoir parameters, was applied to solve different possible cases.

The proposed interpretation technique was tested during simulated examples and comparing the results to those obtained from conventional techniques. A comparison between the use of equivalent time (the rigorous method) and real time to analyze a multi-rate injection test was made.
Real-Data Analysis Brings Large Benefits in Hydraulic Fracturing in a Moderate Permeability Oil Reservoir in Kazakhstan
Authors: Shaoul Josef R. , Folmar Edgar , Arman J. V. , van Gijtenbeek Klaas
Published: December 2007

Real-Data/Real-Time analysis of fracture stimulation data is a valuable tool for fracture engineering in the field, especially in fields where there is a large variation in well to well behaviour. The differences in behaviour can be due to reservoir heterogeneity, differences in depletion, lateral heterogeneity, different fracture growth mechanisms and varying completion types. In such cases, a standard "cookbook" fracture design is not possible.

In this paper, the authors present a case study based on 12 fracture treatments in 10 wells in the Arman field, a moderate permeability oil reservoir with significant water and gas production. The field is also under water flood in some zones, leading to large variations in reservoir pressure from zone to zone. We first look at using real-data analysis to calibrate a fracture growth model by comparing predicted results for a fracture treatment design with the actual pressure data recorded during the treatment. We also give examples of dealing with such real-world issues as operational problems, reservoir heterogeneity, tortuosity, multiple fractures, high spurt loss and calibration of tip-screenout behaviour, and show the successful application of a fracture modelling tool to deal with these issues.
Hydraulic Fracture Spacing in Horizontal Chalk Producers: The South Arne Field
Authors: Wesnæs Ken , Hasbo Klaus , Ginty William R.
Published: December 2007

Horizontal producers completed with multiple hydraulic fractures have proved cost effective in several North Sea low permeability chalk fields1,2,3,6,7. This paper describes the evaluation of the optimal stimulation type and spacing for five South Arne pre-drilled producers that were planned to fill the process design capacity.

The initial design work consisted of both analytical and numerical simulation methods. These were calibrated using a South Arne porosity to permeability transform, stimulation design software predicted fracture geometries and offset field production experience.

Most wells were drilled in a direction that was parallel to the hydraulic fracture orientation. Propped fractures placed in a near tip to tip fashion were found to be the optimal design. Based on this and the initial production data a batch completion operation was performed and the platform capacity reached. A comparison with two years of production history has been made which supports the main initial design assumptions and results. Earlier papers on the stimulation and completion work of the South Arne development1,6,7 are complimented by the reservoir engineering issues covered in this paper.
Effect of Initial Water Saturation on Spontaneous Water Imbibition
Authors: Li Kewen , Chow Kevin , Horne Roland N.
Published: December 2007

The effect of initial water saturation on gas recovery by cocurrent spontaneous water imbibition and imbibition rate was investigated both theoretically and experimentally. Equations correlating initial water saturation, gas recovery, imbibition rate, rock/fluid properties, and imbibition time were derived and used to conduct the theoretical analysis. These equations foresee that gas recovery and imbibition rate could increase, remain unchanged, or decrease with increase in initial water saturation, depending on rock properties, the quantity of residual gas saturation, the range of initial water saturation, and the units used in the definitions of gas recovery and imbibition rate. The theoretical predictions were verified experimentally by conducting spontaneous water imbibition at five different initial water saturations, ranging from 0 to about 50%. Water phase relative permeabilities and capillary pressures were calculated using the experimental data of spontaneous imbibition. The effects of initial water saturation on residual gas saturation, water phase relative permeability, and capillary pressure were also studied experimentally. The results in different rocks were compared. It was found that the residual gas saturation by spontaneous imbibition in a fired Berea sandstone sample (clay was removed by firing) was lower than in a natural Berea sandstone sample (clay was not removed). This demonstrates significant wettability alteration caused by firing. In other words, there may be significant wettability differences among different gas-liquid-rock systems.
A Case History: Use of a Casing-Conveyed Perforating System to Improve Life of Well Economics in Tight Gas Sands
Authors: Eller J. Gary , Garner J. Jay , Snider Phil , George Kevin
Published: December 2007

This paper provides the first technical review of a casing-conveyed perforating technique to fracture stimulate multiple sands in a single wellbore. This is an alternate well completion methodology to improve life-of-well economics. Two wells in Kenai, Alaska were recently completed using this system. The system consists of perforating guns mounted external to the casing and integral valves in the casing for zonal isolation. All equipment is remotely actuated without wellbore intervention. The first well was completed with 15 perforating modules and the second with 12 modules, each placed over a 1,700’ (520M) gross interval. This case history recounts the installation of these completions and their subsequent perforation and fracture stimulation. Both completions are considered technical and economic successes.

The casing-conveyed perforating technique was chosen for these Beluga Sand wells in an effort to improve life-of-well economics and total hydrocarbon recovery. An exhaustive characterization study of this multiple-pay environment recognized that conventional completion techniques were not adequately developing the resource. Low-quality Beluga sand bodies represent a large potential target of reserves, but the economics of conventional completion techniques never allowed this potential resource to be stimulated and properly evaluated. Use of this new completion technique meant that all pay sands, even those low-quality sands that had conventionally been ignored, could now be effectively and economically stimulated. Minifrac data, tracers, and production logs are used to evaluate the productive potential of these low-quality Beluga Sands.
Permanent Fiber Optic Monitoring at Northstar: Pressure/Temperature System and Data Overview
Authors: Kragas Tor K. , Turnbull Bill F. , Francis Michael J.
Published: December 2007

In-well fiber optic sensing systems offer the potential for continuous, high accuracy, high reliability data measurements. Over the past two years, permanent downhole fiber optic pressure and temperature monitoring has become an accepted new technology in the oil and gas industry. Northstar, on the North Slope of Alaska, represents the first multi-well, new field development to incorporate downhole fiber optic pressure and temperature monitoring. This paper will describe the fiber optic pressure and temperature systems being installed at Northstar. Data collection, data management, and data application will be discussed and examples of data from the first installations will be given.
Multiphase Flowmeter Applicaton for Well and Fiscal Allocation
Authors: Theuveny B. C. , Mehdizadeh Parviz
Published: December 2007

Traditionally, well allocation and fiscal allocation have been performed on the basis of test separator information. The technology breakthrough of multiphase flowmeters brings new solutions to allocation solutions. These new flow rate measurements have demonstrated some unexpected well behavior. These dynamic effects (instability, slugs) have shed light on the origin of some back-allocation factor issues experienced in some fields. The paper discusses actual causes for large back-allocation discrepancies and provides examples of challenges to standard test separator.

This paper also presents the decision strategies related to the implementation of multiphase flowmeters to determine allocation issues. The paper discusses the impact of uncertainties of multiphase flowmeters on the overall fiscal allocation and provides recommendations on installation methodologies and screening processes to make best use of the dynamics of these new measurements.

The understanding of the different needs for well test information and allocations is illustrated and the impact to the allocation factors is shown. The distinction between well-specific tests and diagnostic information from pad/manifold fiscal allocation is important to the hardware selection process and to the back-allocation issues. The impact of the frequency of the measurement is also quantified. The paper concludes with a series of recommendations to improve back-allocation factors on existing installations
The Effects of Magnetic Treatment on Calcium Sulfate Scale Formation
Authors: Farshad Fred F. , Linsley J. , Kuznetsov O. , Vargas S.
Published: December 2007

The problem of scale deposition in oil wells, gas wells, surface production equipment, and also the scale deposition in the flow lines, has presented a challenge to the petroleum industry since the first wells were drilled more than one hundred years ago. Although scale deposition is a major problem that interferes with the production of oil and gas, it is not the only large problem. There is the second problem concerning the treatment and removal action of scale deposits, which greatly adds to the overall cost of oil and gas production. These two problems often make marginal wells uneconomical. The petroleum industry has long sought more effective ways of dealing with this problem and the historical treatment methodologies remain relatively unchanged. Significantly, these alternatives merely inhibit, but do not prevent the precipitation and deposition of scale. Therefore, producers and operators must endure the ongoing operating costs and problems associated with these control methods in order to continue producing, transporting and processing their scale-infected oil and gas wells. Magnetic technology that prevents scale deposition in oil and gas wells will reduce well operating expenses which is important when considering the large number of low volume stripper wells, both offshore and onshore, in the United States that could benefit from this technology. Magnetic technology will also benefit the petrochemical, paper, food processing, mining, electrochemical, pharmaceutical, electronic, biochemical, metallurgical, nanotechnology, and all the other industries where water is used in the processing of products.
Pressure Behavior of a Well in an Anisotropic Reservoir
Authors: Guira Bendekim , Djebbar Tiab , Escobar Freddy H.
Published: December 2007

Transient pressure tests used to define linear boundaries within a reservoir are affected by anisotropy. This anisotropic behavior of the flow in natural rocks can create major obstacles in characterizing the reservoir. In their mathematical development, conventional methods of analysis use the principle of superposition and direct mirror imaging of wells, which are normally applicable only to isotropic systems.

The method of images was used to generate type-curves for a well located in various multiple-sealing-fault systems and inside closed rectangular reservoir. The transient pressure behavior of a well located anywhere between two parallel sealing boundaries can also be analyzed by type curves. Some research studies have considered anisotropic flow regions.

This paper is concerned with well imaging in anisotropic media for (a) a single well near a single no-flow boundary, and, (b) a single well near a constant pressure line. An imaging method is used to find the image well location, and then a general step-by-step solution is derived which accounts for wellbore storage and skin effects.

Type-curve plots of dimensionless pressure and dimensionless pressure derivative are generated. They clearly show the effect of the anisotropy ratio on the transient pressure response. The application of the proposed general solution is carried out by solving some simulated examples. The calculated distance from well to boundary was found to be in good agreement with the input value of distance to the boundary for the simulated cases.
A Simulation Study of Enhanced Recovery of Schrader Bluff Heavy Oil by Immiscible and Miscible Gas Injection
Authors: Madarapu R. R. , Khataniar S. , Patil S. L. , Dandekar A. Y.
Published: December 2007

The Schrader Bluff Pool is a shallow, heavy oil reservoir in the Alaskan North Slope. Due to the absence of a significant primary drive, enhanced oil recovery methods must be considered for recovering heavy oil from the Schrader Bluff Pool. The objective of this study was to use reservoir simulation to evaluate immiscible and miscible solvent injection processes for improving oil recovery from Schrader Bluff. Typical reservoir heterogeneity encountered in the Schrader Bluff sands was incorporated into the simulation model. Performance of solvents readily available in the area was studied for different modes of injection such as continuous injection, slug and WAG injection. It was concluded that immiscible, lean gas type injectants would be ineffective for oil recovery from the Schrader Bluff Pool. The miscible WAG injection processes appeared to be promising.
Pressure Drawdown and Buildup Analysis in Gas Condensate Reservoirs
Authors: Jokhio Sarfraz A. , Tiab Djebbar
Published: December 2007

This paper introduces a new method to analyze pressure drawdown and buildup tests in gas condensate reservoirs producing under two-phase flow conditions. Integral method of pseudopressure is used to handle the physical properties and the phase change with pressure. The phase change is the result of the retrograde behavior of condensate fluids that occurs within the reservoir when conditions of pressure and temperature are right for it. Resulting phase change causes change in the liquid saturation thereby changing the relative permeability of that phase. To use the relative permeability as function saturation, saturation has to be known at all the times. This method, however, shows how to estimate the effective permeability of the liquid and gas phase as a function of pressure, skin factor, and the arial extent of the different regions at a given stage of the depletion. Effective permeability then can be used to project the well performance during the pseudosteady state, reserves, and well flow potential (AOF).

During pressure test period, which is very short as compared with pseudostaedy state depletion, producing gas oil ratio is assumed constant. In other words oil and gas rates are held constant. In reality it might be hard to do so in a phase changing environment. So, a sensitivity analysis is performed to see the effect of the change in the producing gas oil ratio on the estimation of pseudopressure. We see steady increase in percent error in pseudopressure with increasing pressure at certain percent increase in Rp. At 8,200 psi, 10% percent increase in Rp introduces 3.96% error in pseudopressure. However, the error is 1.49% at 4,000 psi and 0.27% at 1,000 psi respectively. The error at 5% increase in Rp at 8,200, 4,000, and 1,000 is 2.13, 0.79, and 0.14% respectively. It is also observed that the amount of error in the effective gas permeability is 3% and 9% in oil effective permeability.

This paper is divided in four parts. First the pseudopressure is simplified to separate the effective permeability terms. Second, well testing equations are modified in order to provide correlation for effective permeability of each phase. Third, the error in pseudopressure is determined in case over or under estimated GOR value is used. Finally, a field example is solved in a step-by-step manner to show the use of the technique.
A Method for Detection of Untapped Intervals in a Complex Lithology System
Authors: Anthony Taglieri , Doddy Abdassah , Iraj Ershaghi , Kim Halbert
Published: December 2007

This paper is a case study calibrating well log derived lithology indicators with productivity attributes from modern production logs. More than thirty wells drilled thirty years ago into the South Ellwood Field were completed based on limited understanding of the well log responses in the complex Monterey Formation. From a retrospective study of well productivity, Wylie, Ershaghi and Christensen1 presented a pattern recognition technique for identifying productive intervals. Availability of recently obtained state-of-the-art production logs has provided invaluable information about the relevance of the well log derived potential zones to positively tested productive and undamaged intervals.

This paper includes an analysis of the information processing from the Flow View and Gas Holdup Sensor Tool. A calibration of production log data and well log lithology pattern studies is the basis of designing a re-development strategy for untapped intervals not perforated in the initial completion work. Furthermore, the calibration methodology is extended to a nearby field with similar geology for reassessment of reserves potential.
Horizontal Miscible Water Alternating Gas Development of the Alpine Field, Alaska
Authors: Redman R. Scott
Published: December 2007

The Alpine oil field is located approximately 60 miles west of the Prudhoe Bay oil field on the North Slope of Alaska. It contains 430 million barrels of recoverable reserves and 1 billion barrels of oil-in-place. The Alpine reservoir is a Jurassic, marine sandstone with 40-degree API gravity oil with an average thickness of 50 feet. Daily production rates have ramped up from 40,000 barrels in November 2000 at startup to over 90,000 barrels per day in July 2001.

This paper summarizes the development plan evaluation for the Alpine oil field, which is drilling all horizontal wells and flooding the reservoir using a Miscible Water Alternating Gas (MWAG) process. Horizontal wells were selected over vertical wells based on higher expected productivity and improved recovery efficiency compared to vertical wells. Additional horizontal well considerations included aligning wells parallel to potential conductive fractures, using all open-hole completions and selecting an optimum well spacing. The Miscible Water Alternating Gas recovery process was found to be superior to either gas flooding or water flooding for this reservoir. Reservoir strategy considerations included pre-injecting an optimal water volume prior to gas injection, injecting gas prior to water breakthrough at the producers, and optimum distribution of the miscible gas among the injectors.
Approximate Solutions For Flow On Non-Newtonian Power Laws Fluids Through Porous Media
Authors: McDonald Alvis E.
Published: December 2007

Individual well modeling with r-z geometry is often done with a small number of radial cells (e.g. 6 or 7). This usually leads to small space truncation error for black oil systems. for power law fluids a finer grid is required. An example problem is readily solved using 20 radial cells. Coarser definition leads to unacceptable truncation error.

A method is shown to improve finite difference accuracy by space differencing the time derivative. An analytical solution to the difference equation is developed, and used to validate approximate numerical solutions.

Three figures, five tables illustrate results.

1. SUMMARY AND CONCLUSIONS

A small number of radial cells (e.g., 6 or 7) is usually adequate for individual well models using r-z geometry. Our results indicate that solution errors are small for such models when the fluid is a black oil. But errors are not small for power law fluids. The problem discussed here requires 20 radial cells to reduce truncation errors to be acceptable levels. Improved accuracy in the space dependent approximation can be obtained by a suitable space differencing of dp/dt. With such improved accuracy it becomes tenable to use a reduced number of radial cells to model power law behavior. power law behavior. II.

Introduction

Recent papers, developed the following equation describing radial flow of a non-Newtonian power law fluid in a porous medium: power law fluid in a porous medium:

........(1)
A Layered Pattern Simulator For Non-Newtonian Fluids In Graded Viscosity Banks
Authors: Claridge Elmond L.
Published: December 2007

In order to provide a reservoir simulator capable of meeting the needs of a non-Newtonian graded-viscosity bank displacement simulation in heterogeneous petroleum reservoirs, a specialized simulator has been developed. Instead of a finite-difference representation of partial differential equations, the simulator uses integral equations over successive fluid regions in each layer (no cross-flow representation). The Newtonian or non-Newtonian character of the fluids in each region is explicitly represented in the integral for that region. Power-law (pseudoplastic) viscosity behavior is assumed for the non-Newtonian fluids, but the viscosity and the power-law exponent vary with polymer concentration. The required series of terms in the integral equation for each layer is automatically formed by the program as the injection and production history unfolds. A simple example of a polymer flood in a three- production history unfolds. A simple example of a polymer flood in a three- layer five-spot pattern is used to illustrate the application of the program. It calculates very nearly the same rates, but a somewhat program. It calculates very nearly the same rates, but a somewhat different recovery efficiency than does a finite-difference simulator which was adapted as closely as possible for making the comparison.
Aggressive Tip Screen-Out Designs Give North Slope Satellite Field Production a Boost
Authors: Young J. P. , Smith B. W. , Coker M. , Abel J.
Published: December 2007

Over 400 wells have been very successfully hydraulically fractured on the Kuparuk Sand for the Kuparuk River Unit Field (KRU)1. Comparatively smaller petroleum deposits of the Kuparuk Sand have recently been developed in the adjacent Prudhoe Bay Field. These satellite pools, namely the Aurora and Borealis, similarly benefit from fracturing. Significant productivity increases from aggressive Tip Screen-out (TSO) fracture designs have delivered over 40, 000 bopd from 11 wells.

This paper describes the rationale, events and lessons learned leading up to the final very aggressive TSO designs for these satellite wells.

In many cases, fracturing fluid efficiencies measured during datafracs for the satellite wells were approximately two times higher than the Kuparuk Sand analog in the KRU area. Pad volumes during fracturing were as little as 3% of the total treatment volume with modeled proppant concentrations of 5 lbs/ft2 placed.

The majority of wells were S-shaped to minimize fracture complexity. Directional drilling costs, NWPL’s and production results are shown.

Bottom hole pressure gauge data is presented allowing refinement of the designs via net pressure analysis and times to start TSO. Production and pressure transient analysis results are also presented.
No-Damage Drilling: How to Achieve this Challenging Goal?
Authors: Santos Helio , Olaya Jesus
Published: December 2007

No-Damage DrillingSM is the ultimate goal of all well construction activities, by providing a way to explore and produce the hydrocarbon reserves with minimum reduction of the natural permeability of the reservoir rocks. Conventional drilling is conducted with an over-balanced pressure on the reservoir formation, which causes the drilling fluid to invade and damage the rock.

The industry has been trying to come up with alternatives and underbalanced drilling UBD has grown in popularity during the last years. However, in many situations UBD is not feasible to be used, due to economical and/or technical reasons. In cases UBD is not used, a drilling fluid with an overbalanced pressure should be used. A new drilling fluid called Non-Invasive FluidSM – NIFSM has been developed and is in the market to fill this gap.

The goal of this paper is to present a new concept, called No-Damage Drilling, addressing the most important points during a well construction activity. The paper describes the different techniques available to achieve the goal of drilling a well with no-damage, including UBD and drilling fluids. A new drilling fluid is described, which has the capability of not invading the rock when a certain overbalance is applied, and the unique technology of the fluid allows an extremely easy removal of the seal, guaranteeing an effective restoration of the original permeability of the rock.

The paper presents laboratory tests conducted to evaluate the performance of UBD and drilling fluids related to formation damage, as well as several case histories showing that with careful planning and proper technology a successful No-Damage Drilling operation is possible to be achieved. The paper finally addresses the main points to be followed to decide the best technological option to drill with no-damage, based on a series of questions specially developed.
Sag of Weight Materials in Oil Based Drilling Fluids
Authors: Saasen Arild
Published: December 2007

To be able to keep a well under control during drilling it is important to have the weight material suspended during the whole operation. Especially in oil based, or synthetic based drilling fluids, controlling sag is difficult. A large number of wells have experienced lost circulation or well control problems with the associated high costs relating to sag. There are limited field proven methods available to predict the potential for sag for a particular drilling fluid. Therefore, barite sag continues to be one of the most difficult tasks to handle for a drilling fluid engineer. It is well known that standard viscosity readings cannot be used to predict the sag potential of a drilling fluid.

The current paper discusses in detail the mechanisms of sag in oil based drilling fluid and how to treat sag. It is shown that at ultra-low shear rates the oil based drilling fluid is shear thickening as opposed to the shear thinning effect observed at higher shear rates. It is described how this shear thickening behaviour leads to sag if the drilling fluid composition is incomplete. It is described how organophilic clay should be used to minimize sag and why different types of clay have different effect onto hindering sag although none of these differences have to be visible on standard viscometer readings. Furthermore, it is suggested that "modifiers" generally have little effect on preventing sag. Different methods to monitor or predict the sag potential of drilling fluids are also outlined. Dilution of the drilling fluid normally results in increased sag. Good practice is that the dilution with new drilling fluid should be minimized to control the sag properties of the oil based drilling fluid.
One Hole Section-Two Fluids: Optimizing Drilling and Drill In Through Reverse Sequence Solution Engineering
Authors: Reeve Jack , Jones Tom , McNair Gary , Pin Hu Jia
Published: December 2007

An Offshore China/South China Sea operator wanted to optimize the use of a rotary steerable drilling assembly, simplify and reduce operational steps, and provide a larger reservoir wellbore. The operator elected to drill a single 8.5" wellbore and, in order to address a variety of issues and potential problems, change from a Cloud Point Glycol Drilling Fluid to a Drill-In Fluid (DIF) at the reservoir entry point. A reverse sequence solution engineering process was employed wherein planning began from the point of view of a completed well.
Cuttings Transport in Directional and Horizontal Wells While Aerated Mud Drilling
Authors: Naganawa Shigemi , Oikawa Atsushi , Masuda Yoshihiro , Tetsuo Yonezawa , Hoshino Masashi , Acuna P.
Published: December 2007

Cuttings transport in aerated mud drilling for inclined annuli with inclination angles between 30° to horizontal was investigated. Experiments were carried out for over 300 flow conditions using a 9-m long un-pressurized annular test section with 5-in. CSG and 2-in. DP, concentric or eccentric annulus geometry. Two types of base liquids, water and PHPA solution, were used for aerated muds. In the experiments, cuttings were fed into the test section at a constant rate corresponding to a supposed ROP, and the volumetric concentration of cuttings in the annulus under steady state was measured. From the analysis on the variation of cuttings concentration with mud flow rates ranging from sub-critical to critical regions, the critical flow rate (CFR) criterion avoiding a formation of cuttings bed was found to correspond to the cuttings concentration of about 4 vol%. The annular velocity (AV) equivalent to the CFR was as high as 2 m/s in highly inclined eccentric annulus using non-Newtonian conventional PHPA fluid. Air injection significantly reduced the CFR and improved the cuttings transport efficiency in highly inclined annulus except for the horizontal annulus in which much higher AV of about 1.5 m/s was still required to transport cuttings effectively. The result indicates that the flow pattern between gas and liquid considerably affects the cuttings transport performance.
Experimental Determination of Adhesive-Cohesive Bond Strength (ACBS) and Adhesion-Cohesion Modulus (ACM) of Mudcakes
Authors: Amanullah Md.
Published: December 2007

A unique test procedure and a novel test facility have been developed for experimental determination of the adhesive-cohesive bond strength (ACBS) and the adhesion-cohesion modulus (ACM) of mudcakes formed by different mud systems. The test set up consists of a Wykeham Farrance stepless compression machine to embed a cylindrical foot up to a particular depth of the mudcake matrix and then to apply a pulling force to unstuck the cylindrical foot from the mudcake matrix, a digital dial gauge to register the depth of embedment and upward displacement during loading and unstucking process, an electronic balance to register the driving/pulling force during embedment and pulling stages of the test as a function of displacement, a lab jack to elevate the mudcake to a desired height and a PC-based automatic data acquisition system to record the data and monitor the test.

Experimental results indicate significant variations in ACBS and ACM of mudcakes for an identical depth of embedment depending on the composition of the mudcakes. The magnitude of the pulling force and the shape of the force-versus decrease in embedded area curve are influenced by adhesive and cohesive bonding potential of the mudcake material and the nature of the adhesive and cohesive bonds. The presence of electrolyte significantly influences the metal to mudcake and mineral to mineral bonding. The hydrated ionic diameter of the cations also has some effect on the adhesion and cohesion properties of mudcakes. The presence of barite within the mudcake matrix causes a significant increase in ACBS and ACM of the mudcakes probably due to the filler and mass adhesion effects of barite particles along with the molecular forces of interactions. The effect of three fluid loss additives such as modified starch, CMC and PAC on the ACBS properties of NaCl-Bentonite mudcakes has also been investigated. The presence of CMC and modified starch in NaCl-bentonite muds has little effect in the ACBS and ACM of NaCl-bentonite mudcakes. However, the presence of PAC in NaCl-bentonite mudcake causes some increase in ACBS but a significant reduction in ACM. The results of the test could provide useful information regarding bonding potential of different mudcakes to drill pipes, reamers, stabilisers and drill bits and also drill cuttings in case of cuttings bed formation in directional and horizontal wellbores. The test method can be used for mechanical screening of drilling mud additives and the results can be used in designing drilling muds to produce desirable mudcake quality.
New Shared Organization-Learned Project Management System provides a Knowledge Hub for Integrated Reservoir Optimization
Authors: Drnec M. L. , Balci B. , Etkind J.
Published: December 2007

Knowledge capture, distillation, preservation, and sharing among project teams are challenging issues across widely distributed organizations. The teams need to share information, learn about and apply best practices and lessons learnt, in a structured, easily accessible manner: anytime and anywhere. The implementation of a project management system integrating worldwide, web-accessible organizational-learned knowledge hub is presented in this paper.

A Project Knowledge Portal (PKP) was implemented; containing links to corporate web based Knowledge Hub, including a structured repository for all project critical information. The Integrated Project Management System (IPMS) was developed as a process matrix, based on a company wide implemented standard. The PKP uses the IPMS to create an ISO 9001 compliant structure behind all applied project processes.

Organizational knowledge is generated, captured, distributed and preserved throughout every stage of the project. The team uses the PKP to create a one-stop-shop for project knowledge. The project specific management system is stored in the Project hub together with all associated documentation such as standards, procedures, manuals, roles & responsibilities, audit & review systems, records, etc. All project members have access to the management system anytime. The records of the system are generated by team members and posted into the Project Hub. The required changes to the system are made via the Project Hub to the project member that maintains project specific management system.

Knowledge Management (KM) components of the web based PKP include real-time synchronous and a-synchronous E-collaboration tools to capture decision processes and have an audit-able trail for document control. The Portal includes a static filing repository in the form of the Schlumberger Knowledge Hub. QHSE Data, Lessons Learned and Best Practices are captured and made available for the rest of the organization. An example of implementation is presented in an actual project, with details of the roles and responsibilities and the impact on organizational learning.
Viscosity Predictions for Crude Oils and Crude Oil Emulsions Using Low Field NMR
Authors: Bryan J. , Kantzas A. , Bellehumeur C.
Published: December 2007

Knowledge of oil viscosity is vital to the petroleum industry, and is especially important when considering production of heavy oil and bitumen. As viscosity increases, conventional measurements become progressively less accurate and more difficult to obtain. Oil viscosities measured in the lab may also be not indicative of true in-situ viscosities. An alternate method is required for predicting oil viscosity, especially if this method can be applied in-situ. Stable crude oil emulsions are prevalent in many stages of the production and transport of heavy oil and bitumen. Knowledge of emulsion viscosity is necessary for determining energy requirements for transport and upgrading of the produced crude.

Low field nuclear magnetic resonance is examined in this work for its potential to predict viscosity of crude oil and crude oil emulsions. NMR is an attractive alternative to conventional viscosity measurements, because it can provide fast, unbiased and non-destructive data. A correlation is presented that predicts fluid viscosities from under 1 cP to over 3 000 000 cP over 25 – 80°C, making it valid over a wider range of viscosities and temperatures than any other published NMR viscosity correlation. With tuning, this model can predict very accurate changes in viscosity with temperature for a single oil. An NMR emulsion viscosity model is also presented that uses the oil viscosity and water fraction, both determined from NMR, to predict emulsion viscosity. This correlation is able to provide order of magnitude emulsion viscosity predictions for a wide range of emulsion water cuts and viscosities. Work has also been done to extend the viscosity predictions to in-situ viscosity measurements, which can then be extracted from logs. Preliminary findings on in-situ oil viscosity are encouraging, and indicate that NMR has great potential as a tool for in-situ viscosity determination.
Characterization of Acid Gas Diffusion in a Carbonate Fractured Reservoir through Experimental Studies, Numerical Simulation and Field Pilots
Authors: Lagalaye Y. , Nectoux A. , James N.
Published: December 2007

Injection of acid gases in fractured reservoirs will be one of most challenging issue in the future for many carbonate fields over the world.

A genuine integrated approach to characterize acid gases diffusion on a carbonate fractured gas field has been developed including laboratory experiments, huff & puff pilots, experiments history match and up-scaling for a full-field dual-porosity model.

First, pre-simulation have been realized to appreciate the feasibility of measurements of acid gas diffusion between a diffusion chamber (pseudo-fracture) and a core saturated by field representative acid gas and irreducible water.

Second, an original laboratory experiment enabling acid gases diffusion measurements has been successfully realized.

Third an history match of the experiment at small scale has been realized. Activity corrected molecular diffusion coefficients and tortuosities have then been up-scaled at 3D full-field scale for a dual medium system passing by intermediate up-scaling models.

Meanwhile huff & puff pilots injecting pure methane have been conducted. The final history match of these pilots enabled to evaluate both diffusion phenomenon and exchange surface between fracture and matrix medium.

The availability of this diffusion characterization for an acid gas injection is ensured by the use of the activity-corrected diffusion formulation which makes the diffusion coefficients independent on pressure, temperature and phase composition under specific conditions.

This method enabled to evaluate with a good confidence the economy of an acid gas re-injection project on a fractured reservoir. It makes possible acid gas diffusion mechanisms and block size evaluation.

The laboratory experiment constitutes a new technical approach to evaluate a fractured medium acid gas diffusion.

The technique used to match and upscale the mechanism constitutes also a technical breakthrough.

Finally the method integrating laboratory experiments, compositional dynamic up-scaling and operational pilots for acid gas diffusion characterization in carbonate fractured medium constitutes a major technical improvement.
Inversion of Multi-Phase Petrophysical Properties Using Pumpout Sampling Data Acquired with a Wireline Formation Tester
Authors: Wu Jianghui , Torres-Verdín Carlos , Proett Mark A. , Sepehrnoori Kamy , Belanger David
Published: December 2007

Modem pumpout wireline formation testers (PWFTs) can collect a wide array of data during the pumpout phase of fluid sampling. Both flow rate and pressure are sampled in time during the pumping process and are used to infer apparent permeabilities under the assumption of single-phase fluid flow. Numerical simulation of multi-phase flow has been successfully used to describe filtrate invasion and the resulting pumpout contamination as a function of pumping time and rate. Recent developments in invasion modeling also allow one to simulate the invasion profile for either water-base or oil-base filtrate invasion when the mud properties are coupled to the invasion process. Because of these developments, it is now possible to determine more complex multi-phase petrophysical properties of rock formations. In this paper, we report on a new inversion technique used to estimate petrophysical formation properties from data acquired by a PWFT.

First, a 3D numerical sensitivity study of PWFT data is carried out over a wide range of formation properties including variations of permeability, anisotropy ratio, and porosity. Results from this sensitivity analysis are used as test cases for the inversion algorithm to estimate formation parameters and their uncertainty in the presence of noisy measurements of pressure and flow rate. Inversion is performed making use of a neural network approach. We appraise the robustness and efficiency of the inversion algorithm with actual field data. The estimated formation parameters are further compared to core and wireline data.
Enhanced Gas Recovery by Carbon Dioxide Sequestration in Depleted Gas Reservoirs
Authors: Mamora D. D. , Seo J. G.
Published: December 2007

A depleted natural gas reservoir can store significantly more gas than a depleted oil reservoir (with the same initial hydrocarbon pore volume) for two reasons. First, ultimate gas recovery (about 65% of gas initially-in-place) is typically about twice that of oil (average 35% of oil initially-in-place). Second, gas is some 30 times more compressible than oil or water. CO2 has a critical temperature of 31°C (88°F) and a critical pressure of 7.38 MPa (1070 psia). Consequently, at pressures and temperatures typically encountered in the field, carbon dioxide will behave as a supercritical fluid. However, displacement of natural gas by supercritical CO2 has not been done in the field and is not well understood.

As part of a CO2 sequestration study, we have conducted experimental and analytical studies to evaluate the feasibility of displacing natural gas with supercritical CO2. The experiments involved injecting supercritical CO2 into an aluminum Hassler core-holder containing a 1-ft long by 1-in. diameter carbonate core initially saturated with methane. Rate and composition of the produced gas were measured, enabling determination of mole fraction of produced CO2 as a function of time. In addition, the core holder was CT scanned to determine core porosity, and CO2 and methane saturation. Experiments have been conducted for core pressures in the range, 500-3000 psig at 70°-140°F. Results indicate that some 73%-87% of the gas initially-in-place is recovered at CO2 breakthrough, with a low CO2 dispersion coefficient of 0.01-0.12 cm2/min.

We can tentatively conclude that CO2 injection into depleted or abandoned gas reservoirs would not only sequester CO2 but would also re-pressurize the reservoir, and most likely result in effective displacement of the gas. Thus, production of hitherto unrecoverable gas reserves could help defray the cost of CO2 sequestration: in short, a possible win-win technology.
New Underbalanced Perforating Technique Increases Completion Efficiency and Eliminates Costly Acid Stimulation
Authors: Behrmann L. A. , Hughes K. , Johnson A. B. , Walton I. C.
Published: December 2007

Cased and cemented horizontal wells in the East Painter field in Wyoming have historically been perforated with modest underbalance pressures of 300 to 600 psi and then acid-stimulated to achieve economical production rates. The moderate success rate and expensive acid stimulations provided the motivation to evaluate other options for obtaining cleaner perforations.

Conventional perforation-design techniques suggested that an underbalance of about 4000psi is needed to produce clean perforations for the low-permeability rock in this field. This would require a low wellbore pressure. An alternative is to use the PURE* (Perforating for Ultimate Reservoir Exploitation) system to create a high dynamic underbalance from a modest initial under or over balance. Two laboratory tests were conducted to evaluate these alternatives. The knowledge gained from these and other laboratory tests was used to modify the perforating techniques in the East Painter field to increase well production. Perforating gun design was changed, and the perforating process was modified to provide a substantial dynamic underbalance with only a modest initial underbalance.

This new dynamic underbalance concept provides transient underbalances up to about 80 percent of the reservoir pressure without applying the equivalent static initial underbalance. This technique increased well performance, and eliminated the costly acid stimulation step by generating cleaner perforations and higher effective shot density. In this paper, details of the gun modifications and perforating process will be described along with specific well-performance data. Comparisons to previous perforating practices are also included.