bluuebunny/crossref_metadata_2025 huggingface dataset:
Drilling with Casing: The Mexican Technique Uses the Casing as a Drillpipe
Authors: de León Mojarro José C. , Terrazas Martin , Santana Victor M. , Eljure Abraham Julián
Published: December 2007

Everybody believes to drill a well, it is obviously necessary to use Drill Pipe. Pemex Exploration and Production (PEP) has drilled with Tubing more than a 150 gas wells since June 1996. Now PEP went further, cause PEP already drilled with 5 ½" Casing Hydril Series 500 Type 521, the gas well Culebra 281 in the area of Burgos Basin in Reynosa, Tamaulipas, Mexico.

This Mexican Technique uses the Casing as a Drill Pipe. The 5 ½" HD-521 Casing drills the first section with a 12 ¼ in. tricone bit and the second section with 8 ½ in. PDC bit. After the first section is drilled, the 9 5/8" Casing with guide shoe and float collar is run and it is cemented from the bottom to the surface. The second section is drilled with the same 5 ½" Casing to the programmed depth and finally the same 5 ½" Casing is run with guide shoe and float collar in stands in order to be cemented as an Intermediate Casing.

In both sections, the 5 ½" HD-521 Casing is rotated during drilling and it is retrieved to the surface in stands to lay down the drill bit and bottom hole assembly (BHA).

The third section and last section is drilled with 2 7/8" HD-533 Tubing, 4 ¾ in. PDC bit and 3 ½ in. Mud motor and then it is retrieved to the surface to lay down the drill bit and bottom hole assembly (BHA); finally the completion is done with the same 2 7/8" HD-533 Tubing which is run in stands with guide shoe and float collar to be cemented as a Production Casing (Tubingless Technique). The Mexican technique improves the return on investment, due to the fact, No Drill Pipe is required to drill the well and also this technique reduces drilling time and well cost.
Using Particle-Size Distribution Technology for Designing High-Density, High-Performance Cement Slurries in Demanding Frontier Exploration Wells in South Oman
Authors: Jain Bipin , Raiturkar A. M. P , Holmes Chris , Dahlin Andrew
Published: December 2007

A promising oil source in South Oman is providing challenges to successful cementing operations. The formation is approximately 4200m deep with bottom hole pressure of 13000psi. There is a very narrow margin between the formation pore and fracture pressures. Also salt saturated mud with weights up to 17.5 lbm/gal is routinely required to drill these wells.

There has always been a conflict with conventional oilfield cements between optimizing slurry properties for mixing and placement and resulting mechanical properties of set cement necessary for long-term zonal isolation. This conflict is even more evident in high-density environment where achieving slurry which is stable, mixable and pumpable frequently results in sacrificing set cement mechanical properties as compressive strength, permeability and porosity.

The challenge has been successfully dealt with in cementing high-pressure wells in South Oman using a technology adapted from the concrete industry. Particle Size Distribution (PSD) optimizes both slurry and set cement properties simultaneously. Extensive lab testing and yard trial prior to field application demonstrated the superior performance of High Density High Performance Slurries (HDHPS) over conventional cements in both the liquid phase and when set.

To date eight jobs have been performed and following improvements have been seen.

Average waiting on cement time has been reduced by 50% for plugs. Much higher success for plug setting compared to three successful plugs out of the previous seven with conventional slurries. Reduced difference between the planned and actual cement heights for plugs. Well cemented critical production liners shown by Cement Bond Logs.

Details of the slurry technology are presented along with data documenting the jobs done to date in South Oman. The system is widely accepted by operator in Oman and is the preferred system for critical high pressure cementing.
Field Testing of Advanced Turbodrill
Authors: Cohen John H. , Maurer William C. , Long Roy C. , Johnson Orren , De La Rocha Baudelio Ernesto Prieto , Saucedo Nicolas Rodriguez
Published: December 2007

An advanced 9e-inch high-temperature turbodrill has been developed that uses a gear box to increase the turbodrill torque to 7,800 ft-lbs and reduce the speed to 80 rpm, making it ideal for use with roller and PDC bits in hard rocks. The high torque output eliminates stalling problems associated with high-speed turbodrills, making these turbodrills easier to run in the field. In laboratory tests, this turbodrill drilled a 12¼-inch hole in granite at 96 ft/hr, while in the field it drilled at rates of 207 ft/hr compared to 76 ft/hr for rotary drilling. The turbodrill will operate at temperatures up to 400• F, making it ideal for horizontal drilling in deep, hot gas, and geothermal wells
Riserless Drilling With CaCl2 Mud Prevents Shallow Water Flows
Authors: Turner K. M. , Morales L. J.
Published: December 2007

The Mars basin is notorious for having among the worst shallow water flows (SWF) in the deepwater Gulf of Mexico (GOM). In August of 1998, the SWF sands at the southern end of the basin were successfully drilled riserless to 2105' BML with 25,000 bbls of weighted CaCl2 mud stored in the ballast tanks of a semi-submersible drilling rig. The mud system was designed to (1) be mixed and pumped at 1000 gpm, (2) be independent of boats for resupply, (3) maintain constant properties during transport and storage, (4) build a filter cake across 4+ darcy sands, and (5) be quickly weighted up in response to changes in pore pressure as seen with a PWD tool and ROV camera.

This paper presents a case history of the Mississippi Canyon Block (M.C.) 941 #1 riserless drilling interval from planning to execution. It took 4 months to prepare for the 26" hole interval, which drilled in 19-1/2 hours. The unique mud system developed in the lab, and the modifications to equipment and procedures at the mud mixing plant, workboats, and drilling rig are outlined in this paper. It includes details of SWF incidents which occurred during the drilling and cementing operations and how they were successfully controlled/prevented with a weighted CaCl2 mud system.
Drilling Fluid Plays Key Role in Developing the Extreme HTHP, Elgin/Franklin Field
Authors: Fitzgerald B. L. , McCourt A. J. , Brangetto M.
Published: December 2007

The development of the extreme high-temperature/high pressure (HTHP) Elgin/Franklin fields is an example of extending the technical envelope in a safe and cost-effective manner. This paper outlines the successful role of the n-alkane synthetic-base mud (SBM) in the drilling phase of this project. This success was based on the design criteria of the drilling fluid being met in practice.
At-Bit Inclination Measurements Improves Directional Drilling Efficiency and Control
Authors: Skillingstad Torger
Published: December 2007

A system that provides inclination measurements 1 foot behind the bit has been developed to improve the operational efficiency of positive displacement motors while drilling directional holes. This paper illustrates how this new system improves the directional control and drilling efficiency of steerable positive displacement motors. Improvements have been seen in:

Superior sidetracking performance by providing immediate information of when the bit starts to drill new hole. As a result time spent using the traditional "time drilling" technique is greatly reduced. Optimization of sliding intervals. With direct measurement of angle change during "slide" drilling the interval drilled can be optimized to ensure that the required hole angle is neither overshot nor undershot. This reduces borehole tortuosity and improves the gross rate of penetration since the rate of penetration during slide drilling is typically much less than during rotary drilling. Accurate landing of horizontal wells. Targets are more precisely penetrated, hole lengths in the zone of interest are maximized and risks of unplanned sidetrack operations are reduced. Reduced well tortuosity leads to a reduction in torque and drag. The results are easier sliding, less risk of stuck pipe, increased departures and fewer problems with running casing and completions. Reducing wellbore undulations in horizontal wells reduces accumulation of water along the wellbore and leads to increased oil production. Increased response and control of 2-D rotary steerable systems.
Integrated Management Approach Meets Environmental/Operational Goals for Exploration Well Drilled in Peruvian Rainforest
Authors: Elsborg C. C. , Whitney W. S. , Wilde A. F.
Published: December 2007

This paper describes the coordinated approach to the planning and execution that was implemented to maximize all operational efficiencies for a remote exploration well drilled in the rainforest of southern Peru. This synergistic approach enabled the operator to meet all environmental and operational objectives.

For this well, all operations with regard to drilling fluids and waste management were managed as a single entity, allowing the drilling personnel to focus primarily on complex downhole and logistical issues.

The authors will discuss the new approach that combined the drilling fluids and waste management processes under a single site manager. In the planning stages of the well, the integrated process took into account the sensitive environment of the drilling location to develop an applicable site design, techniques to monitor for environmental compliance and to establish individual roles and responsibilities. A drilling fluid system was selected on the basis of its flexibility to promote drilling efficiency while simplifying de-watering and waste treatment efforts. Additional environmental compliance efforts included extensive onsite and laboratory testing of all fluids generated on location, as well as monitoring nearby streams adjacent the well-site to determine the impact of the drilling operation on the jungle environment.

Both the environmental and drilling efficiency objectives were met during the execution of the drilling program. The management processes employed in this well could be applied in other environmentally sensitive locations to minimize drilling wastes, while maintaining drilling efficiencies.
Competitive Performance Drilling with High-Speed Downhole Motors in Hard and Abrasive Formations
Authors: Reich Matthias , Picksak Aeint , John Wolfgang , Regener Thorsten
Published: December 2007

Very hard and abrasive formations are often drilled with impregnated bits and high speed turbines. Typical application areas include the Middle East, onshore Germany, the North Sea, West Venezuela, and Italy. As opposed to positive displacement motors, turbines do not need elastomers in the power section, which can result in better durability in high temperature environments.

Due to its hydrodynamic function principle the power output of a turbine is not linear with the flow rate. A 20% reduction in mud flow reduces the power output by 50%, which drastically reduces ROP in all deep wells, slim holes or lost circulation situations, where it is not possible to operate the BHA with the full flow rate. Furthermore, the use of hydrodynamic power sections does not allow a clear indication of the bit RPM for the optimum operating point or bit stalling via standpipe pressure readings.

In order to overcome these operational difficulties a special high speed positive displacement motor (PDM) was developed. Due to the new design and manufacturing pro-cesses this motor combines the advantages of turbines (high bit speed, low sensitivity with regards to temperature) with the advantages of PDMs (RPM proportional to flow rate and nearly independent of the loading). With the superior torque capability the power output of this new downhole motor is more than double as compared to turbines, resulting in the possibility of using more aggressive bits and increasing ROP.

The paper discusses case histories from Oman, Germany and Italy and directly compares the performance of turbines with the latest design high speed PDMs. The case histories also demonstrate that the use of additional performance tools (i.e. downhole thrusters) can not only significantly improve the steering behavior of the drilling assembly, but also extend the maximum possible horizontal displacement of a well, and minimizes BHA failures.
Novel Jar Technology – The Down-Hole Clutch
Authors: Wijsman C. J.
Published: December 2007

Jarring techniques to free stuck drill strings have been used for decades in the drilling industry. However, jarring in directional and horizontal wells often remains without success. One of the reasons for insufficient jarring success in wells with extreme drag, is the inability to get sufficient pull at the jar. The jar impact forces are insufficient to free the string.

A drill string tool has been developed to enable jarring at high firing loads: the ‘down-hole clutch’. The down-hole clutch enables drill string rotation in the event of getting stuck. Deployment of a down-hole clutch will significantly increase the jarring effectiveness.

The benefits of the down-hole clutch tool in stuck pipe scenarios tool are quantified via torque and drag, and jarring calculations. The calculations to predict the jarring effectiveness are performed using a recently developed jarring simulation program. This program allows modelling of clutch-aided jarring. Other important clutch benefits are the improved hole cleaning and the operational advantage of exactly knowing the jar firing force.

A 6-3/4 inch prototype of the clutch tool has been built in 1999. Based on the calculations and the clutch design, the operational implications of running a clutch tool are reviewed: the placement in the string, engagement and disengagement of the clutch, the loading of the string during jarring and the elimination of the need for a second jar. Future alternative applications for the tool are for instance casing liner running and the down-hole expansion of casing.
Increased Oil Tolerance of Polymer-Enhanced Foams: Deep Chemistry or Just "Simple" Displacement Effects?
Authors: Hanssen Jan Erik , Dalland Mariann
Published: December 2007

In recent years, foam treatment has moved towards field qualification as a practical method for gas shut-off in oil wells producing at excessive gas/oil ratio (GOR). However, the time of gas blockage achieved in most field trials is limited to a few months. This may be too short for general industry acceptance of this economically very attractive niche technology.

Laboratory and scattered field data show that addition of polymers can enhance foam performance in oil-reservoir rock. However, little is known on precisely how addition of polymer improves the application-critical properties of a foam system.

This paper reports new experimental data for gas-blocking foams that appear to have superior oil tolerance caused by the presence of polymer. The results are discussed in a context of field experience with gas shutoff foams and thin-film research.

Core tests were conducted at reservoir temperatures, with crude oils from fields where field trials were done or planned. Systems studied include AOS surfactants and polyacrylamide polymers, bulk chemicals used in the field. Foam performance was measured in gas-blockage mode and forced flow. At zero oil saturation in cores, good foam performance was obtained with or without polymer added and with no systematic trends. Film properties for the same systems similarly gave no clear correlation with polymer concentration.

A new high-pressure cell built to allow direct visual observation of oil/foam interaction at reservoir conditions was used to see if polymer influenced the oil tolerance of AOS-based foams. No effect on the spreading/entering regime was found.

With oil in the core, AOS foams gave positive results only if containing polymer. Foam performance correlated with the level of oil saturation. It was hypothesised that the apparent oil tolerance of AOS/polymer foam was caused by the lower oil saturation in the core during foam generation.

This hypothesis was tested by pre-flushing a core with the polymer/surfactant solution, but then generating gas-blocking foam from a polymer-free foamer solution. The resulting performance was identical to that of the polymer-enhanced foam. Hence, no chemical interactions of polymer and surfactant, or any liquid-film stabilisation mechanism, is required to explain these results. The role of polymer in the systems studied was only to improve the foamer/oil displacement by causing more efficient displacement of oil before or during foam generation. If generally valid, these results have two major consequences:

Product selection by optimising polymer-foam systems for oil tolerance at a given oil saturation level is bound to fail. Foam process design should emphasise the need to create and maintain low oil saturations in the treated zone.
Asphaltene Deposition and Chemical Control in CO2 Floods
Authors: Yin Y. R. , Yen A. T.
Published: December 2007

CO2 miscible gas flooding is a popular method of improved oil recovery. Asphaltene deposition in many of these systems is a costly operational problem associated with the utilization of this method of recovery. A CO2 flood in West Texas was experiencing major problems with asphaltene deposition related ESP failures and tubing plugging.

Operational procedures, field experience and a successful chemical program have greatly reduced the cost of these problems over the last 3 years. A new inhibitor for continuous capillary injection has been recently developed and used in successful field trials. To evaluate the field performance of this new asphaltene inhibitor, a wellhead side stream filter loop was constructed to monitor asphaltene precipitation/deposition. The objective was to measure and compare the time needed to plug a given size filter by untreated and chemical treated produced fluids. Pressure data at the filter loop and wellhead was also recorded to monitor the effectiveness of the treatments.

The field trial results proved the use of a filter-plugging side stream was an effective way of assessing asphaltene inhibitor performance. Based on the filter plugging and wellhead pressure data, it was concluded that asphaltene precipitation/deposition occured if the produced fluid was not chemically treated. The currently used product with successful prior field results was able to reduce asphaltene deposition and doubled the filter plugging time. The new asphaltene inhibitor was shown to be more effective for stabilizing the asphaltenes in the CO2 flooded produced fluids. The new inhibitor extended the time needed to plug a filter by more than four times as compared to untreated fluids.

Case history information, laboratory tests results, side stream configuration, field test procedure and field test results are presented.
Waterflood Redevelopment of the Marmul Haima-West Reservoir, Oman
Authors: Cook R. C. H. , van den Broek L. H. W. M. , Koelman J. M. V. A.
Published: December 2007

The Marmul Haima-West reservoir is being redeveloped from depletion recovery with vertical producers to a line drive waterflood with horizontal injectors and producers. The presence of mica/pyrite rich shale layers within the reservoir sands results in a suppressed log resistivity response. Recognition of this effect led to a 225% increase in field oil initially in place (OIIP) to 1,270 MMstb of 23° API crude. Full-field waterflooding is forecast to increase the ultimate recovery factor from 6% to 24% of OIIP resulting in incremental reserves of 233 MMstb. The pattern waterflood horizontal producers will be completed without downhole sand exclusion. By utilizing horizontal wells and coproduction of sand, well productivity has been increased by a factor of eleven.
IOR Evaluation and Applicability Screening Using Artificial Neural Networks
Authors: Surguchev Leonid , Li Lun
Published: December 2007

The oil industry relies heavily on predictions of the recovery processes in order to make sound operational decisions for reservoir exploitation. For planning of IOR applications, one would like to predict the performance of several competing strategies before making a decision. The main tool for performing such prediction is the reservoir simulator. The reservoir simulators (1) require extensive information about the reservoir that may not be available or can be unreliable in the initial evaluation stage, and (2) are quite computer intensive programs.

Very often decisions on recovery strategies should be taken in an early stage of field development planning. A reliable first order screening evaluation tool enables the makimg of critical decisions on potential recovery strategies with the limited reservoir information. A multicriterion model based, on the method of Artificial Neural Networks (ANN) and interval theory, has been applied to the assessment and screening of EOR/IOR processes, such as water and gas shut off methods. An assessment relies on the existing industry experience and field practice at different reservoir conditions. It is based on applicable ranges for key reservoir parameters (permeability, porosity, depth, fluid properties, heterogeneity, rock type, salinity, etc.). Historic data are used for ANN training by Back Propagation (BP) and Scaled Conjugate Gradient (SCG) algorithms. The ANN model permits an integration of different types of data, eliminates arbitrary approach in making decisions, and provides fast computation and accuracy. The developed ANN model is capable of assessing the efficiency of a large number of EOR/IOR and well shut-off methods even when key reservoir parameters are defective or noisy.
Compositional and Phase Behavior Experimental and Theoretical Work on Hydrocarbon Mixtures and Several Solvents (Carbon Dioxide, Nitrogen, and Flue Gases)
Authors: de Ribeiro Augusto Lino Ulysses
Published: December 2007

Research on compositional and phase behavior of hydrocarbon mixtures and solvents is of great importance to the improvement of oil recovery. Series of experiments consisting of constant composition expansion, multiple-contact processes and constant volume depletion were performed employing three multicomponent hydrocarbon mixtures and four solvents (carbon dioxide, nitrogen and two flue gases). The results permitted to determine the hydrocarbon recovery efficiency for each solvent as a miscible-immiscible-gas process. In the modeling of IOR projects based on miscible-immiscible-gas processes, complex compositional models are employed. These models are based on equation of state (EOS) calculations. As part of the research work performed, an improved cubic EOS model was developed which can be used for more accurate compositional and phase equilibrium calculations than the previous models. The new model is based on a modification of the function used for calculating the cross-parameters aij and bij of the EOS mixing rules. The new model can be used for various applications, including the improvement of the currently used compositional numerical reservoir simulators. The application of the knowledge produced from the experimental and theoretical work presented permits to answer a series of questions such as "Can a flue gas or a mixture of carbon dioxide be used instead of pure carbon dioxide in a particular miscible project?"
Studies of a Relative Permeability Modifier Treatment Performed Using Multitap Flow Cells
Authors: Dalrymple E. D. , Eoff L. , Reddy B. R. , Botermans C. W. , Brown D. , Brown S.
Published: December 2007

Relative permeability modifier (RPM) treatments are designed to (1) reduce the quantity of water produced from the formation or (2) reduce the water-oil ratio (WOR) of the produced fluids without significantly damaging the hydrocarbon-production potential of the zone. Ideally, the RPM chemical should alter the flow properties of the fluids traveling through pore spaces rather than block the pore spaces. However, the laboratory methods and procedures typically used for evaluating RPM's are actually modified versions of those used for evaluating full blocking agents.

The RPM effect is measured by determining the changes in the drag forces through the pore throats to specific fluids (water, oil, and gas) rather than simply blocking the pore throats to the flow of all fluids. Therefore, a different approach was used in the physical-model flow-testing procedure. Flow studies were performed to measure the effectiveness of RPM treatments at distinct points throughout the core as the fluids traveled through rock test cores. The following water- and oil-saturation levels were examined:

100% water water with residual oil oil with residual water

Permeability was varied between −2000 md and 20 md. Placement procedures were also varied. Some tests included single cores; others included treatments of two cores arranged to represent parallel flow stringers within a formation. The two cores, arranged in parallel, were saturated using a method to best represent the type of layer desired; one core represented a water layer, and the other represented an oil layer. A bullhead technique was used for placing the RPM chemical. Both carbonate and sandstone lithologies were examined.

This paper compares the results of conventional testing methods to those of testing methods used for the multipressure tap flow procedure. The results illustrate the importance of examining fluid flow throughout the length of the formation rock sample instead of simply evaluating a single measurement across the entire core. By using a multipressure tap flow cell to determine the effect of permeability changes throughout the length of the core, it was possible to help prevent the observed data from being skewed by "end" effects. This paper also describes laboratory procedures and schematics of the physical laboratory-scale model. Operators can use this information to (1) determine whether an RPM treatment can be applied to water-production problems resulting from sources such as coning and high-permeability streaks, (2) assess the potential damage to hydrocarbon production caused by such treatments, and (3) calculate the treatment volumes necessary for addressing different types of water-production problems.
Potential for Horizontal Well Technology in the U.S.
Authors: Biglarbigi Khosrow , Mohan Hitesh , Ray Robert M. , Meehan D. Nathan
Published: December 2007

The application of horizontal wells has increased tremendously with significant and positive results in the United States over the past decade. The pace of horizontal drilling (for oil) has remained high at about 600 to 1000 wells per year since 1990. Most of these wells have been drilled in three (3) formations: the Austin Chalk (79%) in Texas, the Bakken Shale in North Dakota (5%), and the Niobrara (2%) in Colorado and Wyoming. Wells in other formations constitute about 14%. The Department of Energy National Petroleum Technology Office (DOE/NPTO), working closely with industry, has developed a unique analytical system (including models and database) to asses the potential for the wider application of technology to the balance of the remaining domestic oil resources across a variety of formations. The findings of the DOE effort are the primary scope of this paper.
Experimental Hydraulic Fracture Propagation in a Multi-Fractured Medium
Authors: Beugelsdijk L. J. L. , de Pater C. J. , Sato K.
Published: December 2007

In scaled laboratory experiments, we investigated the interaction of a propagating hydraulic fracture with natural discontinuities. We observed the hydraulic fracture geometry as a function of horizontal stress difference, stress regime, flow rate and discontinuity pattern. We observed the smallest amount of interaction for high flowrates. When the horizontal stress difference was increased, the fracture was smoother. However, when we represented the tectonic stress ratio's, with a lower vertical stress compared with the maximum horizontal stress, we observed a higher fracture tortuosity.
Development of Multiphase Flowmeter Without Radioactive Source
Authors: Fueki M. , Urabe S. , Yamazaki D. , Yamashita M.
Published: December 2007

Development of a multiphase flow metering system, that measures unseparated oil, gas and water flow rates, is one of the key technologies to improve subsea production. The application of a multiphase metering system benefits subsea oil and gas production. Japan National Oil Corporation (JNOC), Yokogawa Electric Corporation, NKK Corporation, Japan Petroleum Exploration Corporation Ltd. and Teikoku Oil Company Ltd. launched a joint project in April 1995 to develop a multiphase flowmeter.

We are developing a multiphase flowmeter, that is safe for both the personnel and the environment, because there is no use of a radioactive source. And it has no moving parts in order to meet the requirement of easy maintenance. The flowmeter consists of two impedance component fraction sensors, venturi-meter and cross-correlation technique with two component fraction sensors.

The performance of this meter was evaluated in both 2[inch] and 4[inch] multiphase flow test loop using lubricant oil or kerosine, tap water, and air or nitrogen as test fluids. Three-phase flow tests were carried out in mixing velocity 3[m/s] with 0.5[MPa] line pressure. The tests for two-phase flow with 0.5[MPa] and 2[MPa] were carried out. Most of the test results show that the total multiphase flow rate error (TM error : specified uncertainty of one phase / multiphase flow rate) of kerosine and water phase are within +/-10[%]. However nitrogen flow rate was under estimated.
Simulating Aerated Drilling
Authors: Sharma Y. , Kamp A. , Yonezawa T. , Rivero L. M. , Kobayashi A. , González J.
Published: December 2007

A steady-state model is presented to study the simultaneous flow of three phase gas-liquid-solid mixtures in conduits. The liquid phase can be comprised of a mixture of Newtonian (e.g. liquid hydrocarbon, water) and non-Newtonian (e.g. drilling mud) fluids. Gas can exist in a free state as well as dissolved in the liquid phase. The model accounts for possible injection of separate streams of gas, liquid hydrocarbon, and water into the conduit. The solid phase is assumed to be fully suspended in the multiphase flow mixture.

Component mass balances are written for the liquid hydrocarbon, water, non-Newtonian liquid, transported gas, injected gas, and solid. The set of balance laws is completed with a mixture momentum equation. Closure of the system of equations is effected by two drift flux equations, relations for fluid properties, mixtures, friction factor, wall shear stress, and component mass fractions. Solubility of gas is described by a black oil behaviour.

An iterative finite difference approximation scheme is used to solve the system of equations. The conduit is divided into segments. The set of equations is solved simultaneously over each segment, and progressively over the conduit.

The model is used to simulate an ubderbalanced drilling operation. The predicted bottom hole pressure compares well with that obtained fromPWD data. The results represent preliminary studies with the model and simulator and serves to identify additional work on a continuing collaborative effort to develop technology related to underbalanced drilling.
Mltbs Project Challenging for Reservoir Benefits
Authors: Kikuchi Shuichi , Fada'q Abdulla S.
Published: December 2007

Multi-lateral completion technology is evolving rapidly and continuing to mature in order to provide new methods for reservoir management and increase production potential.

ZADCO (Zakum Development Company) in conjunction with ADNOC (Abu Dhabi National Oil Company) / JODCO (Japan Oil Development Company) / JNOC-TRC (Japan National Oil Coraporation -Technology Research Center) / ADMA-OPCO (Abu Dhabi Marine Operating Company) and SSDS (Sperry-Sun Drilling Services) has successfully completed MLTBS Phase-1 (Multi-Lateral Tie Back System) utilizing an existing well, a level 5 TAML (Technology Assessment Multi-Laterals) completion and level 4 TAML hydraulic isolation.

MLT(Multi-Lateral Technology) application for the existing well was the first achievement in the world. In addition, several new technologies such as running and full cementing 7" liner in 8-1/2" lateral, recording cement evaluation logs over the cased lateral using TLCS (Tough Logging Condition System), and perforating the cased lateral with one run using TCP (Tubing Conveyed Perforator) were firstly implemented in UAE.

Three years of R&D, integrated planning, and testing were required by MLTBS project team before attempting the extremely aggressive trial.

The ultimate success of the Phase-1 trial on Well-A will encourage introducing MLTBS into Upper Zakum field to -:

Re-establish dry oil production by locating the horizontal section in an optimum layer of upper reservoir. Allow access to upper cased lateral and lower barefoot lateral on demand through the newly designed dual completion. Achieve effective stimulation increasing production capacity of both upper cased lateral and lower barefoot lateral. Leave future options for reservoir monitoring and extending the well life by drilling a secondary lateral or applying selective water shut-off in the upper cased lateral.

MLTBS will provide planning flexibility to exploit reservoirs to their maximum potential, allowing ZADCO to create new development strategies.
Reservoir Modelling Assists Operations to Optimize Field Development: Serang Field, East Kalimantan
Authors: Vo D. T. , Sukerim _ , Ivanowicz Mark , Syahrani _ , Bouclin Denis , Clark Tom , Stites Jim , Partono Yoseph
Published: December 2007

Located offshore East Kalimantan, Indonesia, the Serang Field consists of complex multi-layered reservoirs with strong aquifers and large gas caps. The dynamic change of fluid distribution and saturation in these reservoirs due to production poses a unique challenge for managing and developing the field. Issues important for reservoir management involve locating and defining fluid contacts, optimizing well placement and their timing, selecting proper completion techniques, and identifying potential workover candidates to capture additional recovery.

This paper presents a field case study describing the use of reservoir modeling to assist operations to manage and optimize the Serang field development. The model constructed helps explain the reservoir fluid flow behavior, its production characteristics, and is subsequently used to plan for the field development strategy. Based on modeling results, value-based recommendations are made with focus on selecting optimal infill locations, completion techniques, wellbore placement and timing, identifying workover candidates and recompletion potential, and forecasting flow rates and reserves. Results from current development drilling program with emphasis on using horizontal wells for improving recovery under gas-cap gas and strong aquifer support are presented. Specific strategy used in planning and completing these horizontal wells is also discussed.

The paper demonstrates that reservoir modeling as an integral part of the asset team, plays an important role for technical decision, bridges communication between cross-disciplined team members and becomes a useful forecast tool to help manage the asset and increase its value.
A New Project Evaluation Tool –Risked Rate of Return
Authors: Inoma Akitoshi
Published: December 2007

Hydrocarbon exploration has world-widely become mature and only remote areas are remaining as new frontiers. This brings forth increase of exploration costs. Under these situation, risk analyses or feasibility studies for new projects, especially for exploration projects, have increased their importance. "ROR" has been popularly used for a long time to judge the profitability of projects. But it assumes a discovery of a certain volume of oil or gas accumulation and does not mention the probability of the success. Another important factor to be considered in selection of projects is a probability of the success or a probability of discovery with more than minimum economical size. Recently, the probability is given in a form of probability distribution. A probability distribution of expected reserves and a feasibility criterion such as ROR are still separately used in many companies.

Here I intend to introduce the concept and the calculation procedure of a new feasibility criterion "Risked ROR". This combines the success probability and ROR. By using this concept, plural projects are comparable with each other based on single criterion instead of using two criteria. For this purpose, companies only need to prescribe a certain yardstick value of risked ROR as a company policy.
Development of Pressure Regulating & Heating System for High-Pressure Gas Pipelines
Authors: Mori Takao , Noguchi Akihiko , Nasu Yuuki , Imai Hideki
Published: December 2007

Gas pipelines in Japan tend to be operated in higher pressure than before because of the increase of gas demand.Especially in the latest thermal power plants, a large amount of fuel gas is consumed from high-pressure pipelines for advanced turbine generators or for huge steam boiler systems. In such a power plants pressure and temperature of supply gas should be controlled within the allowed narrow range even if gas demand changes suddenly. We have developed the advanced control system to maintain pressure and temperature of supply gas sent out from high-pressure pipeline via the pressure regulating and heating facility. It has been installed in some large thermal power plants in Japan. This paper describes engineering experiences of this regulating and heating system, and introduces the dynamic simulator that has been developed to predict the vibration in varied situations.
Pressure Derivative Matching Method for Two Phase Fluid Flow in Heterogeneous Reservoir
Authors: Masumoto Kiyoshi
Published: December 2007

Automatic history matching method for simultaneous matching at pressure and its derivatives for two phase fluid flow in heterogeneous reservoir was developed. Adjoint method was used for calculating gradients of new objective function which consists of two parts; one is the original term and the other is the sum of differences between calculated pressure change rate and observed change rate. A set of two phase fluid flow equations which includes capillary pressure are used for calculating pressures and its change rate in the objective function. Quasi-Newton method (Self Scaling Variable Metric Method) was used as optimization algorithm. The one dimensional heterogeneous permeability distribution was estimated with the proposed method for a simple numerical model case. With this method, transient flow behavior in heterogeneous reservoir with multiple phase condition was applied for automatic history matching without too much computing time.
Automatic Continuous-Measuring System of Interfacial Tension by Spinning Drop Technique
Authors: Yamazaki T. , Okabe H. , Akita Y. , Aso K.
Published: December 2007

Surfactant/polymer and alkaline/surfactant/polymer (ASP) floodings have been mostly used in worldwide oil fields as an effective enhanced-oil-recovery method. The principles of these chemical floodings are to reduce the interfacial tension between oil and flooding solution of alkaline/surfactant.

The spinning drop technique has been used to evaluate the interfacial tension between oil and the solution by measuring the shape of the oil drop in the flooding solution contained in a capillary tube. Until now, the shape of the drop has been measured by micrometer of a microscope. This method, however, often brings on human errors and a great time-loss. In order to eliminate these defects, an automatic measuring system has been newly developed by combining a video-image analysis, an automatic recording system, and a computer for calculation of the interfacial tension under the spinning drop technique. The features of this system are as follows:

It enables to measure and record the interfacial tension automatically for a long time. It enables to change the measuring time and the recording interval very easily by programming. It reduces human errors and contributes to laborsaving.
A New Technique to Confidently Characterize Wettabilty Alterations Induced by Drilling/Completion/Workover Fluids
Authors: Rao D. N. , Bassiouni Z. A.
Published: December 2007

Formation damage, although limited to the near-wellbore regions of the reservoir, plays a major role in productivity impairment simply because all the produced fluids must flow through this region. This damage could consist of permeability reduction due to deposition of particulate matter (fines, mud solids, asphaltenes etc.) as well as wettability alteration. While the permeability reduction and its possible remedies have been well-characterized in laboratory core floods, the wettability alterations induced by the interactions between the rock and the various fluids used in drilling, completion and workover operations have remained difficult to characterize. This difficulty is mainly due to the uncertainty in the techniques we have been using to characterize wettability, which has led to an aura of skepticism surrounding laboratory measurements of wettability. Some of the reasons for this state of affairs are the lack of reproducibility of contact angle measurements even after using live reservoir fluids and long aging times, and the unrepresentative (or non-reservoir) conditions under which the Amott and USBM tests are generally carried out.

This paper presents the recently developed dual-drop dualcrystal (DDDC) technique which has been used successfully in several oil-field applications to generate reproducible measurements of both the water-advancing and water-receding contact angles at reservoir conditions of temperature and pressure using live reservoir fluids. Unlike the conventional contact angle tests, which require 30-40 days to complete, the new technique enables these measurements within 2-3 days while assuring measurement accuracy within about 2-3 degrees.

The paper presents the methodology and salient features of the new technique, some of the recent results to demonstrate its accuracy and short run times, and actual reservoir cases involving serious wettability shifts caused by brine incompatibility, scale deposition, temperature variation and a workover fluid invasion. Due to its accuracy, short run duration and operability at reservoir conditions, the new technique offers excellent potential for detailed understanding of the influence of the various components of drilling/completion/workover fluids on wettability alteration, screening and optimization of fluids for field applications, and evaluation of remedial measures to combat formation damage.
Effect of Carbon Dioxide on Hydrogen Sulfide Scavenging
Authors: Salma T.
Published: December 2007

Effective removal of hydrogen sulfide (H2S) is one of the challenging problems associated with the production of natural gas. Since H2S is often present in natural gas along with varying levels of carbon dioxide (CO2), selective removal of H2S from sour gas in the presence of CO2 is very important for cost effectiveness of a scavenging operation. For over ten years, triazine based scavengers have been successfully applied in the sweetening of natural gas. However, observations of the effect of CO2 on the scavenging capacity of triazine based scavengers have not been very consistent. Initial documentation and case histories on performance of triazine based scavengers by Dillon [1,2] reported that CO2 did not have any effect on the H2S scavenging capacity of triazine. However, recent studies by GRI [3] indicate that CO2 significantly reduces the H2S removing capacity of triazine. To address this discrepency, this paper critically evaluates the effect of CO2 on the scavenging performance of a triazine based H2S scavenger. Results from controlled laboratory experiments, using a wide range of CO2 partial pressure and H2S to CO2 ratios indicate that CO2 has very little effect on the H2S scavenging performance of a triazine based H2S scavenger. Field data supports the observations made in the laboratory experiments.
Reservoir Engineering Aspects of CO2 Sequestration in Coals
Authors: Seidle John P.
Published: December 2007

With increasing worldwide CO2 emissions, interest has risen in injecting CO2 into coals to mitigate their possible role in global warming. Concepts from natural gas storage are readily adapted to CO2 sequestration in coals. The classic p/Z plot for describing stored gas inventories is modified for CO2 sequestration using the p/Z* concept developed for understanding conventional coal gas recovery. Coal often exhibits stress dependent permeability and this relationship is used to identify the optimal depth for CO2 injection. CO2 fillup of a coal seam is described by coupling a gas injectivity equation with a mass balance equation. Example calculations are presented for two selected basins.
Viscoelastic Surfactant Fracturing Fluids: Applications in Low Permeability Reservoirs
Authors: Samuel Mathew , Polson Dan , Graham Don , Kordziel Walt , Waite Tim , Waters George , Vinod P.S , Fu Dan , Downey Rich
Published: December 2007

The introduction of viscoelastic surfactant (VES) base fracturing fluids has changed the way industry views fracturing fluids and proppant transport during a fracture treatment.1 Elimination of polymers allows one to achieve highly conductive proppant packs with no polymer damage. Retained permeability and leakoff control are two of the most important requirements for fracturing fluids. Traditional and new generations of cross-linked gels provide good leakoff control, but they often adversely affect the retained permeability of the proppant pack. In addition, minimizing frac-height growth and increasing effective fracture length are a few other advantages of using VES fluids.2

In the majority of cases in low permeability formations, a long and conductive fracture is the ultimate aim of hydraulic fracturing. Borate or metal crosslinked guar fluids, because of their inherent high viscosity, typically result in height growth rather than increased fracture length. With VES fluids proppant transport is based on the elasticity and structure rather than the viscosity of fluid. Therefore VES fluids efficiently transport proppants at lower viscosities. At the same time, VES fluids let one achieve a better fracture geometry, that with minimum fracture height and maximum fracture length. Pressure transient analysis and tracer studies have shown that this non-damaging low viscosity fluid can give longer effective frac-length even when using much less fluid and proppant volumes (Figure 1). Reduced friction pressure is another added advantage while using VES fluids. Hence VES fluid is the fluid of choice when fracturing is performed through coiled tubing.3,4 Simplicity and reliability of this two component system are the other features of this fluid that attract the industry globally.5

The use of VES technology is now extended to other oilfield applications, such as selective matrix diversion,6 filtercake removal,7 and coiled tubing clean out. VES technology is also defining new engineering practices in hydraulic fracturing that cannot be accomplished with conventional fluid systems, such as fracturing through coiled tubing.