bluuebunny/crossref_metadata_2025 huggingface dataset:
Predicting Gas Condensate Well Productivity Using Capillary Number and Non-Darcy Effects
Authors: Narayanaswamy G. , Pope G. A. , Sharma M. M. , Hwang M. K. , Vaidya R. N.
Published: December 2007

The objective of this work was to provide a more accurate prediction of well and reservoir performance for gas and gas condensate reservoirs by investigating near-wellbore effects. Specifically, the effects of non-Darcy flow and changes in relative permeability due to interfacial tension (IFT), and flow rate (modeled based on capillary number) on well productivity are considered. These effects are shown to be important factors affecting the productivity index (PI) of gas condensate wells. When only non-Darcy effects are considered, the condensate bank can cause an order of magnitude reduction in the PI. Hence, immediate remediation steps might be necessary for formations with high non-Darcy flow coefficients. The reduction in PI with increasing non-Darcy flow coefficient is also highly non-linear. The relative permeability improvement obtained at high capillary numbers on the other hand counteracts the PI reduction due to non-Darcy flow effects. This effect reduces the drop in PI due to condensate buildup and makes the drop in PI more gradual. Hence, both effects should be considered while studying the production performance of a gas condensate reservoir. The capillary number effect can in some cases overshadow the two-phase non-Darcy effects. Interestingly, when both non-Darcy and capillary number effects are present, the rate of decrease in the PI at or below the dew point is smaller than the case with the capillary number effect only. A case study of a lean-gas condensate reservoir, similar to the Arun field, was considered and a history match with the production data was performed. Simulation results are presented which clearly show that accurate prediction of PI based on laboratory measurements is possible using both non-Darcy and capillary number effects.
Modular Mesh Generation with Embedded Streamline Potential Grids
Authors: Edwards Michael G , Li Bin , Aziz Khalid
Published: December 2007

Reservoir grid generation can be simplified by decomposing the domain into a set of subdomains such that modular grid generation can be performed within each subdomain. The question of how to decompose the domain is addressed. Streamline-potential coordinates form an integral part of our domain decomposition strategy.
Steady State Solutions of Immiscible Two-Phase Flow in Strongly Heterogeneous Media: Implications for Upscaling
Authors: Stephen Karl D. , Pickup Gillian E.
Published: December 2007

Steady state solutions of the classical equations for immiscible two phase flow (mass balance and Darcy's Law) have been used successfully in numerical upscaling in the limits of viscous or capillary dominated flow. At low flow rates in strongly water wet or mixed wet media, capillary pressure moves the fluids rapidly at the local scale. For viscous dominated flow, once the flood front has passed, local displacement is fast compared to the change in fractional flow. For upscaling, this fractional flow can be considered as a local boundary condition. The advantage of these steady state methods is that they are much faster than conventional dynamic methods such as those of Kyte and Berry (1975), Stone (1991), requiring what is effectively a single phase solution to the flow equations.

More often, flow rates are between extremes and the above non-dynamic methods are no longer applicable. Steady state solutions can still be obtained though the numerical methods are more elaborate. Dynamic simulation can be performed until steady state is achieved with constant fractional flow boundary conditions. However, this is more time consuming than that required for conventional dynamic methods and thus a more direct method is required.

We present a fully implicit method which will obtain steady state solutions directly and thus improve the speed of calculation.

Simulations involving strong capillary forces depend heavily on internal boundary conditions defined by rapid change of either permeability or wettabillity. Continuity of capillary pressure must occur across these boundaries. The exception to this condition occurs for oil trapping (Van Duijn et al, 1995). For water wet rocks, this will happen for flow from high to low permeability rocks and the hydrocarbon will become trapped (Figure 1). In these conditions, the final steady state can be dependent on path and initial conditions. We demonstrate that capillary trapping depends not only on the form of the capillary pressure curves but also on the model boundary conditions as they vary in time.

Results from the direct implicit steady state solver mentioned above are compared to those from dynamic simulation of waterflooding (Figure 2). Effective relative permeability curves from steady state upscaling techniques are compared to contrast the different degrees of capillary trapping. It is shown that fully implicit steady state solutions will provide a good approximation to the full fine scale model (Figure 3).
Staggered in Time Coupling of Reservoir Flow Simulation and Geomechanical Deformation: Step 1 — One-Way Coupling
Authors: Minkoff Susan E. , Stone Charles M. , Arguello J. Guadalupe , Bryant Steve , Eaton Joe , Peszynska Malgorzata , Wheeler Mary
Published: December 2007

An isothermal, implicit, mixed finite element black oil reservoir simulator from the University of Texas is coupled to an explicit, quasistatic, nonlinear finite element solid mechanics code from Sandia National Laboratories. Both codes are 3d and parallel. The former models (in a locally conservative manner) the flow of oil, gas, and water fluid phases in the reservoir while the latter has been specialized to solve large-scale geomechanics problems involving significant inelastic deformations. In this paper we illustrate a uni-directional coupling of the two codes in which flow simulation output (pore pressures) from a 10-year test case based on the Belridge Field in California drives the geomechanics simulation for the same time period. The high-porosity, low-permeability Belridge diatomite undergoes significant compaction including 6 feet of vertical displacement at the top of the reservoir.
Simulation of Coupled Thermal/Fluid-Flow/Geomechanical Interactions in Fluid Injections
Authors: Rewis Adam , Chen Her-Yuan , Teufel Lawrence W.
Published: December 2007

Production/injection induced geomechanical issues in petroleum operations have been gaining more and more emphasis recently. Realistic modeling, monitoring, and controlling of flow-induced stresses are essential (and also present challenge) to reservoir management. This paper presents a numerical 2D finite-difference model incorporating the complex thermal/fluid-flow/geomechanical interactions. Non-isothermal effect (e.g., a cold-water flooding) is emphasized.

The paper describes (i) model development, (ii) model verification, (iii) simulation results, and (iv) practical implications and model limitations. Governing equations (heat flow, rock elastic deformation, and fluid flow) and the associated initial/boundary conditions are described. Control-volume-based numerical discretization/algorithm is outlined. Published analytical solutions are compared to verify the model. Effects of thermal and fluid-flow (pressurization) are isolated to show the relative importance of each mechanism.

Compared to the conventional isothermal or thermal reservoir simulators, describing flow- and thermal-induced evolution/distribution of reservoir stresses is the unique feature of the presented simulator. Simulation results indicate that thermal-induced stresses can alter reservoir stress anisotropy (in both magnitude and direction). The principal implication is that alteration and reorientation of permeability anisotropy could occur by two potential stress mechanisms: (i) permeability reduction by pore-volume compressibility effect, and (ii) permeability enhancement by flood-induced fracturing. Future work is to study the impact of the altered permeability on the sweep and recovery of a flooding project.
Advances in Coupled Geomechanical and Reservoir Modeling With Applications to Reservoir Compaction
Authors: Settari Antonin (Tony) , Walters Dale A.
Published: December 2007

Coupled geomechanical and reservoir modeling is becoming feasible on a full field scale. This paper describes the advances of the coupled model described previously1, its extensions for modeling compaction and the application of the model in full field studies.

The advances of the theory and numerical implementation since the original work1 make it practical to perform full field coupled studies with complex, realistic description of the geomechanical behaviour of the reservoir and shales, which allows prediction of stress changes, reservoir compaction and surface subsidence. These capabilities are demonstrated in field examples that analyze and predict classical pressure induced compaction in a gas field as well as thermally induced compaction in a heavy oil field. In both cases the methodology of interpreting the geomechanical laboratory and field data and its integration in the coupled modeling process was the key to obtaining a realistic predictive tool. The examples demonstrate that the technology is maturing to the point that conventional studies can be converted to coupled modeling on a fairly routine basis.
Nested Gridding and Streamline-Based Simulation for Fast Reservoir Performance Prediction
Authors: Gautier Yann , Blunt Martin J. , Christie Michael A.
Published: December 2007

Detailed reservoir models routinely contain hundred of thousands to several million grid blocks. These models often cannot be used directly in a reservoir simulation because of the time and memory required for solving the pressure grid on the fine grid. We propose a nested gridding technique that efficiently obtains an approximate solution for the pressure field. The domain is divided into a series of coarse blocks, each containing many fine cells, for which effective mobilities are computed. The pressure is then found on the coarse scale. The pressure field within each coarse block is computed using constant flux boundary conditions obtained from the coarse pressure solution. In this way, a continuous but approximate velocity field is computed on the fine grid. The method is similar to the first step in a multigrid pressure solution. Streamline-based simulation is used to move saturations forward in time. The pressure field is periodically recomputed, taking account of the fine scale permeability and saturation distributions. We test the method for a series of example waterflood problems and demonstrate that the method can give accurate estimates of oil production for large 3D models up to 8.5 times faster than direct simulation using streamlines on the fine grid, making the method overall approximately up to 1,000 times faster than direct conventional simulation. The method is thus able to handle multi-million grid blocks problems easily, enabling simulation to be performed directly on detailed geological models. It is a robust alternative to traditional upscaling, since the effects of changing boundary conditions are automatically accommodated.
An Implicit Treatment of Upscaling in Numerical Reservoir Simulation
Authors: Guedes S. S. , Schiozer D. J.
Published: December 2007

In this paper, it is proposed a multi-scale computational model for multiphase flow that implicitly treats upscaling without using pseudo functions. It overcomes some practical difficulties related to the use of the traditional pseudo curves by executing the upscaling and solution processes in just one step and taking into account changes on the numerical model in an adaptive manner.
A Technique for Generating Reservoir Simulation Grids to Preserve Geologic Heterogeneity
Authors: Stern D. , Dawson A. G.
Published: December 2007

To accurately represent the underlying geologic model, simulation models must preserve important geologic features. This paper describes a technique for optimally selecting simulation model layers to preserve the heterogeneity in the geologic model. The technique involves selecting optimal locations for simulation model layer boundaries, and determining the number of layers needed. Starting with geologic model layering, the simulation model is sequentially coarsened by combining layers to give the smallest possible difference between geologic model properties and simulation model properties. As the simulation model is coarsened, calculations of sweep efficiency for unit mobility displacements are performed to determine how many layers are needed to adequately describe the heterogeneity of the fine-scale geologic model. This technique has two main advantages over existing technologies for layer selection: 1) it provides a quantitative method for determining the number of layers required to preserve heterogeneity, and 2) although the objective function is flow-based, it does not require extensive computer resources to solve the single-phase flow equations on the geologic model grid. As a result, it is easily applied to very large geologic models.
Lessons Learned from Over 300 Producing Well Water Shut-off Gel Treatments
Authors: Portwood J. T.
Published: December 2007

The economic lives of many wells are shortened due to the expense associated with handling excessive amounts of water production. Additionally, hydrocarbon production may be restricted as a result of high producing fluid levels that are commonly associated with high water production. Excessive water production in natural waterdrive producing wells usually results from either "coning" through matrix rock or from vertical fractures that extend into and conduct water from an underlying aquifer. Over the past eight years, Chromium III Carboxylate Polyacrylamide gels have been placed into more than 300 producing wells in such a way as to reduce water flow and lower fluid levels resulting many times with increased oil production due to improved drawdown. Typical water shut-off treatments reduce water production 75% to 90% and, depending on the formation and the cause of the water problem, oil production can be increased by as much as 1,000%. Gels have been applied to fractured and matrix permeability reservoirs, and to both carbonate and sandstone formations.

This paper will focus on providing practical polymer gel information that, when used in conjunction with normal operations data, can be readily reduced to practice. Topics to be discussed include candidate selection criteria, job sizing, gel strength, treatment strategies, treatment monitoring and evaluation, risk factors, results and lessons learned. Economic data including project payout, cost per incremental barrel of oil produced and success rate will also be discussed. Case studies will be presented to demonstrate what is actually working in the field and what can be expected from a successful treatment.
Model for Hot Oil Jobs
Authors: Kenyon Douglas E.
Published: December 2007

This paper describes an Excel spreadsheet used to solve a challenging transient heat transfer problem in a well. A large number of unknown temperatures are solved numerically as a function of time on an R-Z grid. Time steps are controlled by a macro and the formulation is fully implicit for numerical stability. The situation modeled is hot oil injection into a well annulus in attempt to warm the tubing, thus melting wax and allowing its removal. Often the tubing is pumped while it is heating. Hot water or wax solvents are sometimes used in place of hot oil. The annulus may be (and often is) partly empty when annulus injection begins. The location of the injected fluid front is determined from annulus injection rate and other well data. When the injected fluid reaches the annulus sump level near the bottom of the well, that sump level rises rapidly because injection rate generally exceeds annulus drainage rate. This rising sump level slows the possible downward advance of injected heat, which may not reach the needed depth. Examples reveal that the injected fluid cools with depth and that may affect job success.
Gas Well Production Optimization Using Dynamic Nodal Analysis
Authors: Bitsindou A. B. , Kelkar M. G.
Published: December 2007

This work presents a numerical algorithm that permits the production optimization of gas wells using the concept of dynamic nodal analysis. By combining the desirable features of nodal analysis, material balance technique and decline curve analysis, the method is able to match the historical performance of the well data. It is also able to predict the future performance of the gas well under the existing condition as well as altered conditions. The proposed technique, which has several advantages over the classical nodal analysis, can be used for the selection of the timing and capacity of surface compressor, the evaluation of the economic viability of a well stimulation, and the understanding of the effect of individual production component on the productivity of a gas well over the life of that well.
Field Reporting Through the Internet
Authors: Boone D. M.
Published: December 2007

There are now a number of new hardware and software tools that can allow us to easily and efficiently report daily production and operational data from the field using the Internet as the communications medium. The Field Data Collection system described in this paper includes a central secured database that is updated via the Internet and would be available to anyone with the appropriate permissions. The system provides all the input and reporting requirements needed by the operators. Anyone with proper permissions can access the data from anywhere in the world through various pieces of equipment including laptops, desktops, handheld PC's, or even from a web-enabled TV.

The paper will discuss the savings that can be achieved with this new field reporting system through a reduction of paper work from field and office personnel and the reduction of costs of managing internal databases and maintaining hardware and software systems. Other advantages include the availability of daily production data in addition to data such as pressures, sales volumes, lift equipment data, and comments. This information is reported in a much more timely manner; within hours instead of days. All of this will result in significantly reduced costs and workload, improved data quality, more detailed and more timely information, which will lead to improved field operations.
High Efficiency Drilling – A Novel Approach for Improved Horizontal and Multi-Lateral Drilling
Authors: Johnson Jack , Schein Gary W. , Moser Terry , Hayes Steven , Liles H. Don , Webb Steven W.
Published: December 2007

This paper describes a novel approach for improved efficiency of drilling horizontal multi-lateral wells in the Austin Chalk formation in the Masters Creek Field of Vernon Parish Louisiana, at TVDs of up to and exceeding 15,000 ft. The typical well drilled in this highly fractured carbonate reservoir consists of two laterals each approximately 4,000 ft. in length. This new approach to drilling with salt water vs. weighted mud was developed because of the extremely high costs of drilling the laterals and, in some cases, not being able to drill the laterals to the desired lengths with mud. Mud losses could be as high as 50,000 Bbls. or more.

This new approach involves the use of high-pressure frac pumping equipment and service iron to provide high rate, high-pressure salt water to drill the horizontal laterals while drilling under a mud cap to maintain control of the well. The high pressure water along with the drilling cuttings are pumped into the fractures of the formation (no fluid returns). This technology has been used on 19 laterals to date and has reduced the costs of drilling these horizontal sections while providing several other advantages. These include less drilling time, lower mud costs, longer mud motor and MWD runs, no lost revenue (as gas is not flared while drilling each lateral), safer operations from a well control stand point since the casing pressure is generally zero psi, and a shorter time flaring the well to a pit until mud production is eliminated so the well can be flowed to production facilities and ultimately to sales.

This paper presents the ongoing results and advantages of utilizing this new approach in drilling these deep high pressure horizontal wells. It also includes the fractured chalk conditions necessary for this process to be successful, the drilling operating pressures and pumping rates used, pumping equipment modification requirements, and cost savings achieved.
Investigation of a New Fracturing Fluid and Conductivity Enhancement Technology on Coalbed Methane Production
Authors: McCabe M. A. , Robert L. M. , Blauch M. E. , Terracina J. M. , Lehman L. V. , Bowles B.
Published: December 2007

Results of recent field trials with a newly developed fracturing-fluid system and liquid surface-modification additive for coating proppant are presented in this paper. The work was performed in the Underpressured Fruitland Coal (UFTC) gas reservoir in the Northern San Juan Basin of Colorado and New Mexico.

This new technology has influenced production in the region. Data of the test-well population are compared to the coal gas and water production from the reservoir. This study identifies and applies the new fracturing system technology for improving production. The results of this study provide information that may apply to other coal-gas reservoirs.

The study group of wells uses hydraulic fracturing treatments consisting of a new low polymer loading crosslinked fluid system with a proppant surface-modification additive. The fluid system has increased crosslinked-fluid viscosity, requiring a lower gelling-agent concentration. A liquid additive that coats the proppant and increases its surface adhesion is added in the blender tub during the treatment. The surface friction between the coated proppant grains resists high flow rates during cleanup. Modifying the proppant also influences the migration behavior and blocking effects of fines (coal and precipitates) within the propped fracture.
A Comprehensive Rod-Pumping Model and Its Applications to Vertical and Deviated Wells
Authors: Xu J. , Doty D. R. , Blais R. , Shahraki A. , Lea J.
Published: December 2007

This paper presents the modeling of a sucker rod pumping system for both vertical and deviated wells. It focuses on the derivation and applicaton of a new set of comprehensive equations that incorporate both the dynamic rod motion as well as the fluid flow through the annulus between the rod and tubing. The mathematical model for a deviated well is developed using the principles of virtual work. Partial differential equations, and their associate boundary conditions, have been derived to describe the dynamic performance of the system in great generality. The model incorporates all system components and most downhole pump inflow conditions. The effect of lateral rod deformation between the couplings is evaluated by introducing effective longitudinal stiffness and by the Garlakin method. The model for deviated wells incorporates not only viscous friction, but also Coulomb friction. The model’ results are validated against actual measured data. Numerous examples are presented to demonstrate the application of the new technique for the design, analysis and optimization of sucker-rod pumped wells, specially deviated wells.
High Volume and Compression Cages for Subsurface Sucker Rod Pumps
Authors: Ivey R. K.
Published: December 2007

Inefficiencies in sucker rod pumping systems due to gas interference are major concerns for petroleum producing companies throughout the world. This paper describes an innovative cage design that is based on years of exposure to sucker rod pump inspection and repair from many varied field conditions and on compression and flow comparison testing. Observance of results obtained from working closely with the Alberta Research Council in Edmonton Alberta on numerous projects specifically related to conventional, thermal, vertical and horizontal sucker rod pumping was also influential. The creative cage design addresses the two features that are absolutely essential to good standing cage performance. These two features are (1) high compression capability and (2) large flow capacity. The equipment used to perform the flow and compression testing allowed actual visual observation. The tests compared many different cage designs and demonstrated how those design differences affected cage performance.
Proppant Conductivity — What Counts and Why
Authors: Lehman Lyle V. , Parker Mark A. , Blauch Matt E. , Haynes Randy , Blackmon Alan
Published: December 2007

The emergence of "accepted" proppant conductivity testing methods has led to much discussion about what is needed to regain high conductivity levels, and several marketing campaigns have been based on these findings. The industry has generally accepted the principle that delivering high conductivity levels in the fracture is key to achieving high production levels. This paper does not refute this point, but modifies it.

This paper presents theory, laboratory data, and case histories indicating that high initial conductivity levels can only gain high initial levels of potential or actual production. For sustained, high production levels, the proppant pack's integrity must be maintained. With time, most proppant packs are damaged by fines migration, gel clogging, and geochemical precipitation. These processes can be abated with various additives and techniques. This paper discusses these techniques in detail and shows case histories in which the techniques proved costeffective in sustaining higher levels of production than those found in comparable wells.
Exploiting a Reservoir, An Evaluation of Recompletions in the Dakota, Wattenberg Field, DJ Basin
Authors: Emrich Clark A.
Published: December 2007

Resurgence in activity has taken place within the Wattenberg Field of the DJ Basin by deepening existing J-Sand completions approximately 100 feet to the Dakota sandstone formation. The deposition of the Wattenberg Dakota is contained in various shoreface environments. Underbalanced drilling has been the common practice in deepening existing wellbores. Once deepening is concluded, the well is completed open hole. Drilling underbalanced has occasionally yielded favorable results producing the well without stimulation. This may be indicative of natural fracture networks related to faulting. Usually an effective stimulation treatment needs to be placed on the Dakota for it to be an economic success. Due to the favorable results of the play, new drill sites targeted for the J-Sand may be drilled to depths of potential Dakota reserves using conventional mud drilling methods. Well logging will determine if there is a viable Dakota formation. If log signatures indicate potential, the wellbore is cased and the zone stimulated. To date, no wells drilled with mud in this case study have produced naturally.

Dakota production in two areas of interest within the Wattenberg field of the DJ Basin was evaluated. Drilling and stimulation procedures were examined. Well productivity was evaluated using the Reciprocal Productivity Index (RPI) method, well test analysis, and core analysis in an effort to determine the least damaging and cost effective method to exploit the Dakota reservoir. The proximity of wells to normal faults, thus possible permeability enhancement due to natural fracture swarms, will be examined in an effort to determine if such geologic occurrences improve the chances of exploiting the Dakota reservoir.
Start-up of a New Generation Mechanised Drilling Package for Platform Drilling Operations : The Brent Charlie – a Step Change in Performance
Authors: Porteous Steve , van Elst Herman , Leil Drew , Shuttleworth Nigel , Hindriks Hendrik
Published: December 2007

In March of 1997, the Brent Charlie NDES (New Derrick Equipment Set) commenced drilling and workover operations on the Shell/Esso Brent Charlie platform. Expectations were very high for this new breed of mechanised drilling unit. The initial performance was disappointing and the anticipated time/cost savings were not realised. The warranted performance could not be achieved and a number of high potential incidents occurred.

A step change in the performance was achieved and the trend of high potential incidents eliminated through the project approach of a dedicated performance improvement team. The participation of experienced vendor representatives on the project team and drill crew input was critical to the success of the project. The follow up of a structured HAZOP analysis of the mechanised functions in the derrick played a major role in the reduction of the high potential incidents.

Specialised crew training to operate this new breed of drilling unit has led to the development of advanced rig training systems. Hands-on training is no longer sufficient. Underpinning knowledge of the fundamental logic system needs to be taught, understood and tested; simulators need to be developed to teach crews the systems and equipment, allowing experience to be safely gained away from the workplace.

This paper presents the Brent Charlie NDES; from the rig concept and initial performance expectations to the experiences as the rig commenced operations. The performance improvement project, including HAZOP study, resulting in restored operational efficiency and confidence in the safe operation of the new rig is presented. Lessons learned, equipment upgrades to the new rig and enhanced crew training is discussed.
Case History: Utilizing 5-1/2" Drill Pipe in a Deepwater Gulf of Mexico Drilling Program
Authors: Jenkins Roger W. , Greenip John F. , Adams Burt A.
Published: December 2007

This paper describes lessons learned while selecting and utilizing a string of 5-1/2" drill pipe with special reduced clearance outside diameter (OD) tool joints in a long-term deepwater Gulf of Mexico drilling program. Actual field data including hydraulic analysis, fishing considerations, trip-speed, and completion uses are chronicled. The paper also discusses using the string of drill pipe to drill inside a 9-5/8" drilling liner along with tieback and completions inside 9-5/8" production casing. Savings associated with using one string of drill pipe are presented. Inspection results and all damages are discussed. A comparison of drilling loads, drilling hydraulics and completion hydraulics is made on this string of specialty 5-1/2" drill pipe vs. standard 5" drill pipe along with a limited comparison to 6-5/8" drill pipe. Running and handling aspects are analyzed and discussed. A specific well that utilized this string of 5-1/2" drill pipe was drilled to below 27,500' MD (25,600' TVD) and is described as the example case for the program.
Applications for an LWD Formation Tester
Authors: Hooper M. , MacDonald C. , Shalhope R. , Boonen P.
Published: December 2007

After a well or a well interval has been drilled, zones of interest are often tested to determine various formation properties such as permeability, fluid type, fluid quality, formation pressure, and formation pressure gradient. Currently wireline formation testers are most commonly used to perform this testing. However, the use of these testers is sometimes limited by high operational costs, risk of tool sticking, and invasion effects on measurement accuracy. In addition, wireline formation tests interrupt the drilling process and can add days to a drilling program.

This paper presents field-test results of a recently introduced Drilling Formation Tester (DFT). This tester is part of a logging-while-drilling (LWD) tool string and uses mudpulse telemetry to transmit real-time formation pressure data to the surface. Data obtained from LWD sensors are used to determine the thickness, depth, and petrophysical properties of the formation at the targeted test site in the well. Multiple pressure tests can be performed in a single bit run, thus providing the pressure gradients useful in determining oil, water, and gas contacts. Tests can be completed in less than 30 minutes, with only minimal interruption of the drilling operation.

The field test results are analyzed with a recently introduced exact solution to the spherical-flow well-test equation with storage and skin. The solution is used to predict formation pressure and permeability from early- to intermediate-time pressure transients. This scope is greater than what is possible with conventional drillstem test analysis models, which do not model the early-time behavior. The new solution permits determination of storage coefficient, skin effect, formation fluid compressibility, permeability, and pore pressure.

This paper will explain the concept and the basic design of the new LWD formation tester system, give examples of its applications, and discuss its advantages over conventional wireline formation testers and drillstem testers.
System for Drilling an Offshore Shallow Sour Gas Carbonate Reservoir
Authors: Quitzau R. , Brand P. R. , Tarr B. A. , Frink P. J. , Leuchtenberg C.
Published: December 2007

Special practices and equipment were used to safely and efficiently drill 9 development wells in the sour NSO A Field offshore Indonesia. The objective carbonate reef zone has been notorious for severe lost circulation followed by gas kicks during drilling operations. In the past, rig crews attempted to cure the lost circulation before drilling ahead. This resulted in excessive time and safety risks. Using the system described in this paper, safety was improved and the time to drill the carbonate reservoir was reduced from an average of 16 days per well down to 5 days per well.

A rotating blowout preventer (RBOP) was used to blind drill by pumping seawater simultaneously down both drillstring and annulus. The RBOP allowed surface pressure to be applied on the annulus while drilling and thus enabled the use of cheap seawater rather than expensive mud to hydrostatically overbalance the well.

A special gas handling system was installed to safely burn sour gas. Rig crews were trained to handle the gas and evacuate the rig if necessary. Sour gas was burned at surface on 2 occasions during the project. Eventually, the success of the blind drilling practices enabled the crews to avoid bringing any gas to surface during drilling.

Of nine wells drilled, six wells encountered severe lost circulation. Seawater was injected into these wells to keep the sour gas in the reservoir while drilling or tripping. On 4 of these wells, blind drilling practices were used to reach total depth. Diesel oil - bentonite - water plugs were set in the bottom section of intermediate casing to stabilize the well prior to running pre-perforated production liners with drill-in capability.
Field Data Supports the Use of Stiffness and Tortuosity in Solving Complex Well Design Problems
Authors: Rezmer-Cooper Iain , Chau Minh , Hendricks Andy , Woodfine Miriam , Stacey Brian , Downton Neil
Published: December 2007

Torque and drag analysis has been used for more than ten years to drill wells ‘on paper’. Representations of the drillstring and bottomhole assembly (BHA) that do not include the individual component stiffness have been used with some success in analyzing and preventing problems in extended reach drilling. As curve rates have increased in directional wells and the trajectories themselves become more complex, the effects of the previously neglected stiffness have led to errors in the sideforce calculations that underpin all torque and drag analysis. Finite-element analysis can solve this problem. Additionally, tortuosity can be added to provide a rippled effect to a well trajectory design that simulates the micro dog-legs that occur in the drilled well, enabling more realistic bounds to be placed on the drag and torque losses, and the forces experienced by the drillstring. Tortuosity also allows more accurate modeling of the side forces between the casing and drillpipe, critical to extended reach well design. This is illustrated using a well with a deep kick-off point from the Gulf of Mexico.

A case study based on wells drilled from the Hibernia platform is used to illustrate how the model has been utilized to aid planning decisions and reduce costs.
Underbalanced Drilling in a Depleted Gasfield Onshore UK with Coiled Tubing and Stable Foam
Authors: Nas S.
Published: December 2007

Drilling a sidetrack into a severely depleted gas reservoir is a challenge that can be safely completed using underbalanced drilling technology. Smedvig Offshore completed a sidetrack in a depleted gas reservoir onshore using a rig and a coiled tubing drilling system. A short planning time, a lack of available equipment combined with a restricted operating window and a low budget made this well a challenging project.

Coiled tubing drilling has matured over recent years and the coiled tubing drilling experience gained by Transocean combined with the underbalanced drilling experience gained by Smedvig in the southern North Sea helped to bring this well to a successful conclusion.

The operator is a small independend UK company and required a cost effective solution to this project. The operator intends to convert the field to a gas storage reservoir and to obtain the required injection and production rates wanted to drill a 1000ft horizontal section with a minimum 6" hole size. The reservoir pressure at 1450ft was 240 psi.

The original well was abandoned and sidetracked with a rig. After running and cementing the 7" liner a coiled tubing unit was used to drill the reservoir underbalanced.

Using a stable foam system an annular pressure of 30 psi was obtained. Once gas production started the well was choked back to limit the inflow. Both production and ROP improvement was significant and TD was called after only 750ft of reservoir was drilled because of production rates. The well was completed open hole to ensure maximum hole diameter. No hole collapse or sand production has been encountered.
Planning an Effective Aerated Drilling Operation in Hard Formation Based on Cost Analysis
Authors: Negrão Alvaro Felippe , Duarte Nilo Azevedo
Published: December 2007

The use of air/mist/foam drilling has been increasing over the years bringing advantages not found in conventional drilling. The comparison between the performance of conventional and two-phase flow drilling has shown the second technique presents several advantages to the last one1: (1) minimum or no damage to sensitive pay zones, (2) immediate and continuous evaluation of cuttings for hydrocarbon shows, (3) avoidance of lost circulation, and (4) higher penetration rates in hard formations. Advantages of air/mist/foam drilling regarding penetration rate in hard formation have been pointed out in previous technical papers. Few questions remain regarding the improvement in penetration rate when using this technique. However, questions arise when the main topic is savings attributed to two-phase flow drilling operations. The answers for those questions are not easy because many of the economical factors involved depend on each particular case. There are situations, mainly in wild cat wells, where the operator may not have all necessary input data for choosing the best option between an aerated or conventional drilling technique. Some data are within the direct control of the operator. Others, however, are beyond its influence and control, like the geological uncertainty and equipment performance. The necessary data for an appropriate cost analysis of an aerated operation includes the spread daily rate of drilling rig, the air drilling equipment day rate, the air equipment diesel supply, the air equipment rig up and rig down time, the hard formation thickness, and the expected penetration rate.

This paper focuses on the economics and operational results of using a two-phase flow drilling technique. The intent of this text is to demonstrate how, when, and why an oil company should implement an air/mist/foam operation in hard formation to accomplish the expected economical results. It describes an analysis performed for a wildcat well in Colombia, Los Mangos 60, using all the previous cited necessary data. In that location there were uncertainties related to hard formation thickness and expected penetration rate, so a cost analysis was performed to support a decision about the drilling technique to be used. The analysis used equations and graphs to represent almost all the involved costs, giving support for an appropriate decision. The paper also presents field results collected during the aerated drilling operation, showing that the decision to use this technique was the most appropriate.
Quantifying Bottomhole Assembly Tendency Using Field Directional Drilling Data and a Finite Element Model
Authors: Lesso W. G. , Chau M. T. , Lesso W. G.
Published: December 2007

Predicting the directional tendency of a bottomhole assembly (BHA) is a key element in improving the efficiency of the directional drilling process. Finite element models attempt to represent the detailed physical interactions between the BHA and wellbore while drilling. However, effective use of such models has been hindered by parameters that are difficult to quantify, particularly the strength of the formation and variations in hole gauge.

Details of over 6400 BHA runs made in the Gulf of Mexico from 1994 through 1997 were used in a systematic statistical analysis and combined with intelligent use of the tendency models to yield information that is not readily apparent in single runs of the software. This information can then be used as a predictive tool to minimize the effects of the parameter uncertainties, and to isolate and calibrate those variables to which the models are sensitive. From these studies the most representative values for formation stiffness and hole over-gauge were obtained for various areas within the Gulf region.

We describe a methodology using this combination of advanced modeling and statistical analysis to provide more reliable predictions of BHA tendency and to give an indication of the conditions where such predictive techniques can be effectively applied.
On-Line Torque & Drag: A Real-Time Drilling Performance Optimization Tool
Authors: Reiber Frank , Vos Bart E. , Eide Svein E.
Published: December 2007

A technique for evaluating torque and drag effects in real time and for interpreting the effectiveness of actions taken is presented in this paper. The application determines total wellbore and incremental hole sections friction factors real time using downhole measured weight on bit and bit torque data coupled with surface load measurements or just surface data. In addition the system determines buckling modes, minimum yield and fatigue safety factors. The application enables field personnel to identify drilling performance problems as early as possible.

This paper presents the algorithms and calculation procedures used as well as several case histories from wells drilled offshore Norway, offshore Denmark and onshore Germany.
The Buckling Behavior of Pipes and Its Influence on the Axial Force Transfer in Directional Wells
Authors: Kuru E. , Martinez A. , Miska S. , Qiu W.
Published: December 2007

An experimental set-up was built at the University of Tulsa to study buckling and post-buckling behavior of pipes constrained in a straight horizontal and curved wellbores. Experiments were conducted to investigate the axial force transfer with and without static internal pressure. Different stages of buckling phenomena and their relation to the axial force, the pipe diameter (1/4" and 3/8") and the pipe endsupport conditions have also been investigated. Experimental results have shown that the buckling load is a strong function of the pipe diameter and the pipe end-support conditions. Static internal pressure appears to have insignificant influence on the buckling behavior of pipes.

A brief review of recently developed mathematical models to predict buckling behavior of pipes in inclined, curved and horizontal sections of wellbore is also presented. Applications of the current theory are presented by using recently developed computer simulator. Results of the theoretical analysis have confirmed the versatility and effectiveness of computer simulator for better understanding and solving buckling related problems in the field.
How to Design Rock BitsTo Drill Ultraabrasive Quartzitic Sandstone in Horizontal Wells, Algeria.
Authors: Besson A. , Rabourdin J. L. , Huon W. , Cazenave F.
Published: December 2007

Drilling a long horizontal section within an ultra abrasive formation means short bit runs and high drilling costs. Despite many trials with standard technology bits in this gas reservoir in Algeria, the drilling performances were so poor that the profitability of the development project was greatly reduced.

This paper describes the process to achieve the development of a specific bit design which eventually greatly improved the drilling performance in ultra abrasive sandstone formation and reduced the number of bits used.

The problem analysis was based upon the evaluation of the bit performance history in combination with a full description of the physical characteristics of the rock. The abrasiveness of the sandstone was clearly the main factor which reduced the bit life, particularly in horizontal drilling. In order to increase the run length, the first objective was to reduce as much as possible the frictions of the bit cutting structure against the formation as well as to protect the bit gauge and heel.

The analysis of the rock structure allowed to determine that despite its high abrasiveness, the sandstone presented a hardness weaker than expected. Therefore the penetration rate could be improved with a bit design aimed at favoring the crushing action.

After developping two different bit designs and drilling three wells the rate of penetration and the footage were more than tripled. This is the result of a team work between the bit manufacturers and the operator.
Dual Torque Concept Enhances PDC Bit Efficiency in Directional and Horizontal Drilling Programs
Authors: Mensa-Wilmot Graham , Krepp Tony , Stephen Ita
Published: December 2007

The emergence of PDC bits as viable drilling tools has helped improve operational efficiency in various drilling programs. This is especially true in conventional or vertical hole drilling, where improvements in the application of PDC bits, and their technology1 continue to re-define the known limits of these bits.

However, in directional and horizontal drilling programs, industry acceptance of PDC bits has been "lukewarm", due to a lack of consistent performance in today's environments. As well designs become more intricate - deeper targets, extended reaches and increasing well profile complexities - it is evident that tomorrow's challenges will require new technologies2, 3.

This paper describes a new concept in PDC bit development for directional and horizontal drilling programs. The concept establishes a "dual torque" response, which enhances operational efficiency in both the sliding and rotating modes of deviated hole drilling. Three parameters - sliding slope, rotating slope and transition weight - govern the dual torque behavior. In addition, two sets of parameters – performance requirements and performance objectives4– that define PDC bit efficiency will be discussed.

The paper will establish the relationships between the dual torque concept's parameters, as they relate to tomorrow's directional, horizontal and extended reach drilling challenges. It will show how the concept determines different performance qualifiers in terms of well profile complexities, and operational environments. Analytical and laboratory data, as well as field examples showing the concept's effectiveness and consistency for different deviated drilling programs will also be presented.