bluuebunny/crossref_metadata_2025 huggingface dataset:
Skin Bypass Fracs: Proof That Size is Not Important
Authors: Rae Phil , Martin A. N. , Sinanan B.
Published: December 2007

Hydraulic Fracturing is probably the most widely used stimulation technique in the world today. Practitioners often have pre-conceptions that the process involves huge quantities of equipment and materials, often at vast cost. It is true that this is sometimes necessary. However, often all that is needed to produce effective stimulation – a meaningful increase in production that more than offsets the cost of the treatment and meets realistic production targets – is a conductive path through the region of near wellbore damage. This paper sets out to describe the processes involved in producing these skin-bypass fracs, and with the aid of computer simulations, to demonstrate the effectiveness of these treatments.

The methods detailed in this paper are designed to produce fractures with a maximum propped length of +/− 40 ft. Often these fractures will not completely cover the zone vertically. In spite of this, the data from the simulation studies clearly shows the effectiveness of these treatments. The results also show how variables such as skin factor, permeability, drawdown, net height, frac height, frac length, frac positioning, fracture conductivity, reservoir fluid properties and wellbore geometry influence the production increase. The conclusions drawn from these results are that in many wells effective stimulation can be produced by small, cheap hydraulic fractures, which employ the minimum of equipment and materials.

Skin-bypass fractures are cheap, use minimal equipment and are easy to operate. Furthermore, they are environmentally friendly. They are of benefit all over the world where limitations such as cost, deck space, deck loading and crane size often prevent "conventional" hydraulic fracturing. Skin-bypass fracturing is a viable alternative to matrix acidizing, particularly in formations where unfavourable mineralogy limits the use of conventional acid systems
Large Scale NORM/NOW Disposal through Slurry Waste Injection: Data Analysis and Modeling
Authors: Baker Brian D. , Englehardt John M. , Reid James D.
Published: December 2007

SPE 53821 described a process for NORM/NOW (Naturally Occurring Radioactive Materials/Non-Hazardous Oilfield Waste) remediation that has benefits to industrial, regulatory and general public concerns. For the process to be successful the method must be adequately monitored. Both surface and downhole data must be monitored with a "cradle to the grave" mentality to ensure that the economic success of the process translates to practical safety and long-term containment. This paper describes the monitoring process, data analysis and equipment that was used at the CNO#2, NDW (NORM Disposal Well) site in Fourchon, Louisiana. The paper also discusses diagnostics that could not be applied for various reasons due to locale and well conditions. We will provide a description of the process to date and the "learning curve" of Phase 2 of the remediation project.

Briefly, slurry waste injection is a process to inject slurry of 30-40% solids into a suitably characterized subsurface reservoir. In the case of NORM/NOW it merely means putting back the waste from where it came. The slurry is injected at 14-20bpm (barrels/minute) at 3900-4200 psia (BHP, bottomhole pressure) to 5000 feet. Typically, injection is initiated with clean water at or above fracture gradients. Injection is initiated as a step rate up to fracture pressure. Solid waste is then added to the process until the desired fluid properties are reached. The process is cyclic with 12-hour injection periods and 12-hour falloffs. The 12-hour cyclic process leads to a practical onsite operating scenario i.e. daylight operations with the same operating crew therefore minimising inconsistencies. Pressure data from both the injection and falloff periods are analyzed.

The data acquisition covers a) continuous recording of surface and bottomhole pressures, b) cased hole injection logs, c) surface injection rate and density measurements, d)daily reporting of surface parameters and unusual parameter events, "incidents". The data analysis covers a) step-rate tests, b) injection and falloff tests, c) cased hole log analysis. The open hole log analysis was described in the previous paper and will be further refined here. Several "incidents' are presented to illustrate abnormalities with this kind of subsurface injection.
New Solutions for Subsalt-Well Lost Circulation and Optimized Primary Cementing
Authors: Sweatman R. , Faul R. , Ballew C.
Published: December 2007

Drilling and cementing operations in certain subsalt wells in the Gulf of Mexico (GOM) and other areas have long challenged operators and contractors. These wells have thick, deep salt formations with shear zones just above and below the salt, resulting in high unexpected costs during drilling. Such formations are often referred to as "rubblized" or "disturbed" shale zones. One theory proposes that, during geologic periods, the movement of adjacent salt formations induces shearing stresses that cause deformation, brittle failure, and fracturing in the surrounding shales. Costly drilling problems in these zones are primarily caused by the narrow margins between pore and fracture pressures that result in severe lost circulation, hole instability, and high-pressure kicks. Some of these wells also exhibit uncontrolled gas flows and underground water flows. Many GOM deepwater blocks and shelfblocks have massive salt structures and potential hydrocarbon reservoirs, but the trouble costs and difficulties associated with drilling these wells have forced operators to plug and abandon some wells and completely avoid others.

Conventional lost-circulation and hole-stabilization treatments have been minimally successful in many subsalt wells. However, new wellbore-stabilization and cementing programs designed for subsalt wells can help ensure well control and integrity during drilling and production operations. This paper provides information for helping to improve subsalt drilling operations and lower well-construction costs. In addition, the failures and successes of lost-circulation treatments performed during drilling operations in shear and salt zones will be explained. Primary cementing operations that help provide costeffective zonal isolation and well integrity in these zones are presented, as well as best practices and proposals for cement-slurry design and mud displacement. Laboratory studies and cost comparisons that help justify replacing traditional materials and procedures with these cementing programs are also presented.
Microbial Stimulation of Lake Maracaibo Oil Wells
Authors: Trebbau G. L. , Nuñez G. J. , Caira R. L. , Molina N. Y. , Entzeroth L. C. , Schneider D. R.
Published: December 2007

More than 300 oil producing wells have been stimulated with microorganisms in Lake Maracaibo, western Venezuela, since 1996. Most of these wells are managed by Tía Juana E.U. (Exploitation Unit), PDVSA E&P, Western Area, and belong to reservoir LGINF-05. This reservoir is constituted by four different unconsolidated Miocene sandy intervals, at an average depth of 3,800 feet, average porosity 30%, average permeability to oil of 600 mD and average oil gravity of 25° API.

The wells were injected at the platform using a self-propelled barge, equipped with a triplex pump, at an average rate of 3 bls/min. and were shut-in for 7 days. Fifty (50) wells stimulated in 1997 were monitored for at least 6 months after the injection. Production data is reported and a correlation was made with different geological and reservoir data, to determine the parameters that mostly influenced the effectiveness of the responce.

The results showed a 78% success, with production increments ranging from 30 additional BOPD, to 400 additional BOPD, with an average of 65 additional barrels of oil produced per day. Correlation results showed a better performance on wells with higher bottom hole pressure, located along the erosional axes formed during the deposition period, thus providing the zone with higher oil saturations. The wells with good responce also showed to have cleaner type of sand with less clay associated to it.

This technology has improved the overall production of the reservoir and it has being proved to be cost effective. It is currently being used as a conventional treatment in the Tia Juana District of Western PDVSA.
Producing GOR Used to Predict Permeability Distribution in a Tight Heterogeneous Reservoir
Authors: Wo S. , Weiss W. W. , Balch R. S. , Roe J. , Kendall R.
Published: December 2007

Production from tight reservoirs can yield flow pressures around the wellbores that are below the bubblepoint. The accumulation of free gas around the wellbores results in a rapid increase in the producing gas-oil ratio (GOR). This paper investigates the sensitivity of depletion-drive GOR to variations in permeability. A public domain, black oil simulator was modified to automatically estimate the permeability from GOR histories. The method presented in this paper is especially useful when interpretable pressure transient tests are not available and can be adapted to existing simulators without changing the core code.

A multi-objective, simultaneous bisection algorithm was developed to provide automatic GOR history match and to predict permeability distributions. Following each iterative simulation run, the permeability-searching intervals for all of the wells were simultaneously reduced by half and the permeability distribution map was updated. The updated searching intervals are uniquely determined because the permeability-GOR correlation is monotonic. Usually a satisfactory match is obtained within 10 simulation runs, which is much more efficient than the gradient or stochastic methods typically used for an automatic history matching procedure.

This method was applied to field data from the South Bisti Gallup Pool. Well communication tests have shown a strong permeability preference for a southwest-northeast orientation in the pool's two tight pay zones. The automatic GOR match was applied to the 14-year depletion history of 52 wells. First, the ratio of Kg/Ko was estimated from the total field GOR match. Then, the local variation of permeability was determined according to the GOR history of the wells. Two perpendicular-oriented permeability distributions were obtained. This new method should be valuable for other low permeability reservoirs.
Effects of Wettability on Dielectric Properties of Porous Media
Authors: Nguyen Buu-Long , Bruining Johannes , Slob Evert C.
Published: December 2007

We present in this paper the results of measurements of the complex dielectric permittivity and electric conductivity in oil-wet and water-wet porous media in a frequency range of 300kHz to 1.5GHZ. The porous media are made from unconsolidated acid-purified quartz sand which originally is water-wet. We used silylating agents to convert the same glass beads to hydrophobic oil-wetted surfaces. This avoided the effects of geometry on the dielectric permittivity that would happen if different glass grains are used.

We have made measurements in a specially designed capillary pressure cell with a built-in transmission line which goes through the porous media. The measured capillary pressure curves serve as an indication of the degree of wettability. From the scattering characteristics of the built-in transmission line, we computed the complex dielectric permittivity of the porous media as function of frequency and water saturation

We observed a significant difference in dielectric permittivity of water-wet and oil-wet porous media. At low water saturation, the dielectric permittivity of oil-wet sand is smaller than that of the water-wet one. At water saturation higher than 0.3, the dielectric permittivity of oil-wet sand becomes much larger that that of the water-wet one.

Our results with results show the same trend observed by some previous researchers, but do not agree very well with dielectric permittivity, calculated using mixing models.

This experimental study illustrates the importance of the wetting state of the porous media in determining their dielectric behavior.
Macroscopic Electrical Anisotropy of Laminated Reservoirs: A Tensor Resistivity Saturation Model
Authors: Schoen J. H. , Mollison R. A. , Georgi D. T.
Published: December 2007

Accurate petrophysical evaluation of deep water turbidites composed of thin bedded sand-shale sequences is crucial in the economic decision to explore, develop, and produce these reservoirs. Traditional laminar shaly sand saturation equations are based on a parallel conductivity model that typically results in significant underestimation of in-place hydrocarbons.

Electrical anisotropy is the macroscopic effect of thinly layered sedimentary formations in which logging tools have insufficient vertical resolution to properly resolve individual beds or laminae. Utilizing anisotropy in the saturation analysis transforms the classic "low resistivity shaly sand problem" into a tensor petrophysical model. The tensor shaly sand saturation model is applied to both simple and complex reservoir types with the following results: Simple laminated sand-shale model: Forward model calculations for the resistivity tensors demonstrate the effect of the model variables on net-to-gross, shale resistivity, sand resistivity, and sand porosity. Sand saturation determination is dominated by the vertical component and shale resistivity is dominated by the horizontal component.Complex anisotropic sand model: Forward modeling using alternating fine-coarse grain size distributions within a sand body demonstrates the effect of pore size changes resulting in capillary-induced water saturation profiles. Tensor components for anisotropic sands are presented as an integral expression for any water saturation distribution. The following response of the Resistivity Index (RI) is noted:RI vs. Sw relationship does not follow an Archie-type power lawRI vs. Sw relationship is different for the parallel and perpendicular laminated resistivity components.

The tensor water saturation equation utilizing electrical anisotropy is demonstrated to be theoretically correct for both the laminar sand-shale reservoirs and complex anisotropic sand reservoirs. The significant advantage of the tensor model is a more accurate water saturation determination that minimizes the errors inherent in traditional parallel conductivity saturation equations.
Characterizing Fluid Saturation Distribution Using Cross-Well Seismic and Well Data: A Geostatistical Study
Authors: Idrobo Eduardo A. , Malallah Adel H. , Datta-Gupta Akhil , Parra Jorge O.
Published: December 2007

One of the goals of reservoir characterization, particularly in mature reservoirs, is to identify unswept regions containing high oil saturation for targeted infill drilling or enhanced recovery. A common approach to the problem is to generate high resolution distribution of reservoir properties such as permeability and porosity and then conduct flow simulations to identify regions of high oil saturation. One possible alternative to flow simulations would be to generate spatial distribution of properties that are related to fluid saturations and then infer fluid saturation distribution through the use of appropriate correlations.

In this paper we present a field application to infer interwell water saturation distribution by combining cross-well seismic and well data. First, we use a non-parametric transformational approach to correlate sonic velocity with resistivity and porosity at the wells. An iterative procedure using alternating conditional expectations (ACE) forms the basis for this calibration. Next, stochastic cosimulation is carried out to generate conditional realizations of resistivity and porosity in the interwell region. In this cosimulation, cross-well seismic velocity is considered as the secondary data while resistivity and porosity are treated as primary data. Finally, water saturation distribution is deduced from the resistivity and porosity distributions through the use of Archie's law.
New HF Acid System Improves Sandstone Matrix Acidizing Success Ratio By 400% Over Conventional Mud Acid System in Niger Delta Basin
Authors: Kume Nicholas , Melsen Robert Van , Erhahon Luckie , Abiodun Afolabi F.
Published: December 2007

Matrix Acidizing has been used as the preferred method of stimulating hydrocarbon producing wells in the Niger Delta Basin. The majority of reservoirs in this area are Sandstone reservoirs. Conventional Mud Acid system has been the main HCl:HF acid mixture used in restoring or improving the productivity of these sands. A combination of rapid spending with clays and silicates, matrix unconsolidation in the near wellbore area and subsequent precipitation of various acid reaction by-products has limited the usefulness of Mud Acid for matrix stimulation treatments in this area.

Various attempted solutions using existing fluoboric acid systems and in-situ HF generated acid mixtures have been tried with mixed results. Using statistical data gathered from over fifty wells stimulated with Mud Acid, a major operating company in Nigeria rated the results of these treatments as less than 20 percent, successful in 1997.

A New HF Acid System has been successfully applied on more than thirty wells over the last two and a half years. Field results using the New HF Acid System demonstrate a remarkable increase in the success ratio (greater than 400%) over conventional Mud Acid formulations. Consistent extension in the time to return to pre-treatment production rates has been observed. An increase of 350% in the incremental hydrocarbon production, using the New HF System, has been recorded over results with Mud Acid on the same drainage points. Notable matrix acidizing cost reduction of 25% and a drastic payback time reduction (500%) based on a $12/bbl crude, has been noticed since the New HF System was introduced in the Niger Delta basin.

Actual candidate selection criteria, job design, technical and economic performances evaluation, and the laboratory analysis of core samples from the sands stimulated with this new HF system, have been included in this paper.
A Comparative Study of Straight/Gelled/Emulsified Hydrochloric Acid Diffusivity Coefficient Using Diaphragm Cell and Rotating Disk
Authors: Conway Michael W. , Asadi Mahmoud , Penny Glenn S. , Chang Frank
Published: December 2007

A successful acid fracturing design depends strongly on the rock-acid reactivity. In carbonate reservoirs where the reaction is mass transfer limited, flow rate and diffusion coefficient determine the overall reaction rate. In an acid fracturing program, the value of the acid diffusivity is often unknown to the engineers. Quantifying diffusivity is a key step for a successful acid fracturing design. Diffusion coefficients of straight acids, gelled acids, and emulsified hydrochloric acids were measured with both the diaphragm cell and the rotating disk device. In addition, the data obtained has been utilized to develop a new correlation to predict the diffusivity coefficient of hydrochloric acid, which accounts for the effect of temperature, acid concentration, and rock type with which the acid reacts.
Gas and Liquid-Phase Relative Permeabilities for Cold Production from Heavy Oil Reservoirs
Authors: Tang Guo-Qing , Firoozabadi Abbas
Published: December 2007

Solution–gas drive in two sets of experiments, one with a mineral oil of some 30,000 cp viscosity (at 24°C), and another with a heavy crude of about 10,000 cp viscosity (at 35°C), have been carefully studied. Both oils show recovery in excess of 10 percent at test termination. Should we have continued the test, the recovery would have been higher.

From pressure and flow rate measurements, gas and oil relative permeabilities are estimated by a simple mathematical expression. The results establish that high recovery in heavy oil reservoirs from cold production is not due to the foamy nature of a heavy crude. The results also establish that there may be recoveries in excess of 13 percent, mainly due to the shape of the gas relative permeability curve.
Effective Steamflood Management Using Heat and Mass Balance Model
Authors: Terez Ivan E. , Barnhardt Carl M.
Published: December 2007

This paper summarizes development of a new heat and mass balance model to apply to dipping reservoirs. Previous methodologies and models developed by the Bakersfield Region Office of Texaco Exploration and Production Inc. were evaluated and tested. A new heat and mass balance model was developed to optimize heat management in mature steamfloods in dipping reservoirs. A 30% "safe" margin above the calculated minimum energy requirement is proposed as a target for the reduction of the steam injection into mature projects. The proposed strategy could result in significant fuel cost savings for such projects. Special cases such as reservoirs with very thick formations, unusual pattern orientation, or a high degree of reservoir permeability anisotropy may require detailed numerical simulation, or special parameter adjustment in the application of the model.
Computer Optimization of Large Gas Reservoirs with Complex Gathering Systems
Authors: Holst Richard , Malowany Larry , Kopjar Randy
Published: December 2007

The modeling of large, shallow gas fields, which produce into complex gathering systems was once a difficult and uneconomical task to perform. The optimization of these systems has now become cost efficient through the use of electronic databases and efficient computer modeling software. This paper focuses on the study of a large Hatton shallow gas field in Southwest Saskatchewan, Canada. The field currently has 800 wells (1367 completions) and a complex surface network with substantial line looping and flow splitting. The reservoir is of low permeability and has three isolated productive zones. In 1998, 32 infills were drilled on the basis of adding incremental reserves. Encouraging results led to a desire to further improve the economic performance by infill drilling an additional 260 wells. A model of the surface network and reservoirs was constructed and used to plan facilities modifications upon the tie-in of the 1999 infill wells and to prepare long term forecasts. The study showed that numerical modeling of large, shallow gas properties can be cost effective.
Evaluating the Transport of Solids Generated by Shale Instabilities in ERW Drilling – Part II: Case Studies
Authors: Martins A. L. , Santana M. L. , Gonçalves C. J. C. , Gaspari E. , Campos W. , Perez J. C. L. V.
Published: December 2007

The problem of cuttings transport in the inclined sections of ERW's is a major concern in the oilwell drilling industry. This paper presents a field on the possibility of keeping drilling in the presence of a controlled instability process. The study is supported by an innovative time dependent mathematical model, along with a computer implementation of it, which is based on the well-known two-layer model approach. An innovative feature of this model consists in the consideration of the added amount of solids that comes from the crumbling and cave-in of the wellbore. The model results, coupled with an exponential approach, enables to optimize circulation of different lengths ERWs. The paper represents a further step on the integrated analysis of cuttings transport and wellbore stability problems, aiming cost reduction and safe well design.
A Pragmatic Approach to Managing Wellbore Instability in Extended Reach Wells in the Goodwyn Field
Authors: Tan C. P. , Willoughby D. R.
Published: December 2007

Drilling experience with numerous inclined wells highlighted the issue of wellbore stability in the Goodwyn Field, North West Shelf of Australia. Subsequently, a study, with an emphasis on the longest horizontal well drilled in Australia at that time, GWA 12, was conducted. The aim of the study was to develop strategies to control shale instability during the drilling of future wells in the field. Following the drilling of a number of extended reach wells, a post-drilling review of the wells, including GWA 12, was conducted and the additional information used to revise the critical mud weight contour plots for future application. An assessment was also made of the drilling fluid design for long term stability of GWA 13ST2 based on pore pressure changes induced by key drilling fluid-shale interaction mechanisms.

This paper describes the required information, methods used to carry out the wellbore stability analyses and utilisation of the results from the two studies to develop the recommendations for the mud weight programs of the field. The approach adopted in the studies utilises the relevant field observations in vertical and inclined wells to develop strategies to control instability through theoretical wellbore stability analyses. Reference mud weights, based on drilling experience and wellbore condition in the wells, were used to calibrate the predicted critical mud weights. In addition, design charts of pore pressure change due to mud pressure penetration and chemical potential mechanisms were used to assess the drilling fluid chemistry for long term wellbore stability.
Gas Hydrate Formation and Dissociation with Thermodynamic and Kinetic Inhibitors
Authors: Makogon Yuri F. , Makogon Taras Y. , Holditch Stephen A.
Published: December 2007

This work presents new data on the kinetics of gas hydrate formation and dissociation for methane with water and seawater, with thermodynamic and kinetic inhibitors in static and in dynamic conditions, and several results of the morphology study of gas hydrate crystals. Effective porosity of methane hydrate ranges between 0 - 80%. Hydrate formation and dissociation can proceed simultaneously with transit of hydrate formers from one crystal to the other, both in bulk water and in gas phase with dissolving or sublimation of some crystals and formation of others. At the same time there can be recrystallization of hydrates with change of structure, porosity, and density of crystals.

Metastable state of the system in static conditions may last many hours even at large supercooling with no hydrates. Induction time of hydrate formation depends on structure of water, water and gas composition, pressure and supercooling, cooling rate, dynamic or static conditions. Presence of thermodynamic or kinetic inhibitors may decrease induction time, decrease supercooling and increase rate of hydrate formation. We have tested four different kinetic inhibitors with fresh water and seawater with concentration of kinetic inhibitors from 0.5 mass % up to 5 mass %. Fresh water and seawater formed hydrates in presence of all kinetic inhibitors, which we tested.

Content of natural gas dissolved in water in presence of hydrate at the interface is significantly lower than in water, which is in direct contact with gas. As a consequence, the formation of gas hydrate deposits in nature may proceed more rapidly than the formation of free gas deposits.
A Novel Method to Winterize Traditional Pour Point Depressants
Authors: Manka John S. , Magyar James S. , Smith Robert P.
Published: December 2007

Crude oil producers have used pour point depressants and wax deposition inhibitors with great success for several decades. Unfortunately, undiluted pour point depressants and wax deposition inhibitors are waxy materials that are often solids at the ambient production site temperature. To be able to pump these wax control products down hole, they usually need to be drastically diluted with solvent. The solvent adds to the raw material expense, handling, transportation and storage costs and increases the health, fire and safety hazards of using these heavily diluted products.

This paper introduces an innovative technology that eliminates the need for extensive dilution while improving the low temperature handleability of the pour point depressant or wax deposition inhibitor. This technology does not involve a new type or family of additives. The new process is simply a novel way to deliver traditional performance chemicals down hole.

A patented process1 is used to emulsify waxy pour point depressants and other high melting performance chemicals to yield a product that pumps easily and flows at temperatures as low as −55°F while still delivering a relatively concentrated package. Based on laboratory testing, the emulsified additives retain their original field performance.
Gas-Liquid Metering Using Pressure-Pulse Technology
Authors: Gudmundsson J. S. , Celius H. K.
Published: December 2007

The Pressure-Pulse multiphase metering method is described. The combined effects of water-hammer and speed of sound in gas-liquid mixtures are used to measure the mass flow rate. Through continuity the mass flow rate at the wellhead is the same as the mass flow rate downhole and at standard conditions, making the Pressure-Pulse method suitable for routine production testing and allocation measurements. The method is highly repeatable. Offshore testing of the water-hammer effect and the speed of sound in gas-liquid mixtures, demonstrates the feasibility of the Pressure-Pulse method in petroleum production operations.
Field Evaluations of Different Multiphase Flow Measurement Systems
Authors: Mohamed P. G. , Al-Saif K. H. , Mohamed A.
Published: December 2007

Two multiphase flow meters (MPFM) working on different operating principles were tested (one at a time) in series with a conventional well testing system (test separators and a test tank) at an operating field in Kuwait. The first MPFM utilizes a fluid conditioner to separate the gas, which is measured by a vortex shedding flow meter. Liquid flow is measured with coriolis meter and the water cut is obtained by cyclic sampling and measurement of electrical characteristics and differential pressure between top and bottom of the sample chamber. The other MPFM employs a positive displacement meter, a venturimeter and microwave sensor to measure the flow of total fluid, gas and water respectively. A bypass loop with a vortex shedding flowmeter enables measurement of a larger range of gas flow rate. A number of wells covering a wide range of production rate (377 to 6661 bpd), gas oil ratio (207 to 945) and water cut (0 - 65%) were tested. A turbine flow meter was also included in the tests to measure liquid production rate. Comparative results are presented. Aspects related to foaming and increased back pressure due to MPFMs on well production are discussed along with other key information.
Relative Roughness Chart for Internally Coated Pipes (OCTG)
Authors: Farshad F. , Garber J.
Published: December 2007

The object of this paper is to furnish the engineer with a simple means of estimating the absolute surface roughness, e, and relative roughness, e/D, for internally coated pipes (OCTG). It is very important for design engineers in the oil and gas industry to know the values of surface roughness and relative roughness to properly select, design and install the tubing string. A tubing string is the critical part of the completion program. The tubing must be selected so that production operation can be carried out efficiently; it must be designed against failure from tensile forces, internal and external pressure and corrosive actions. In addition, it must be designed in such a way that maximum production rate and total optimization of the production system is achieved. In 1944, Moody 1 prepared a plot of relative roughness, e/D versus pipe diameter, D, for a number of materials. Moody's1 relative roughness correlation was based on experiments on pipes artificially roughened with sand grains. Moody 1 did not provide the relative roughness plot for internally coated pipes, nor did he perform a regression analysis of the data to provide functional forms of the equations relating relative roughness, e/D, as a function of pipe diameter, D. Currently, internally coated pipes are being utilized in the completion of oil and gas wells worldwide. Consequently, absolute surface roughness and relative roughness values of internally coated pipes are needed by practicing engineers to properly model the hydrodynamics and optimize the production rates in wells 2,3,4. It is important to emphasize that dimensional analysis suggests that the effect of surface roughness is not due to its absolute dimensions, but rather to its dimensions relative to the inside diameter of the pipe, e/D.
Estimating Pore Pressure and Permeability in Massively Stacked Lenticular Reservoirs Using Diagnostic Fracture-Injection Tests
Authors: Craig David P. , Brown Ted D.
Published: December 2007

How does one determine pore pressure and permeability in a well containing 26 reservoirs when pressure-buildup tests are impractical and wireline formation testers have proven ineffective? Operating companies often face this challenge when completing massively stacked lenticular tight-gas sands. During early field development, the pore-pressure differences between sands may be inconsequential to the completion and production of the well; however, as infill wells are drilled, individual sands may be pressure depleted and jeopardize the completion/stimulation of the remaining sands at original pore pressure.

Tight-gas reservoirs in the San Juan, Uinta, Piceance, Greater Green River, and Wind River basins contain fields with individual sands demonstrating pore-pressure depletion. Since many of the massively stacked lenticular sands are stimulated using limited-entry fracture designs, one or two depleted sands can effectively divert an entire fracture treatment from sands at or near original pore pressure.1

This paper describes how multiple diagnostic fracture injection tests are used to (1) identify pressure-dependent leakoff, e.g., from fissure opening (natural fractures); (2) identify pressure-depleted sands; (3) estimate gas permeability; and (4) optimize multiple sand completions. The analysis methods include G-Function analysis for pressure-dependent leakoff, pore-pressure estimates calculated from the stress-depletion relationship of the reservoir rock, and permeability estimates from "conventional" before-closure leakoff analysis and the modified Mayerhofer method.
Fast, Approximate Solutions for 1D Multicomponent Gas Injection Problems
Authors: Jessen Kristian , Wang Yun , Ermakov Panvel , Zhu Jichun , Orr Franklin M.
Published: December 2007

This paper presents a new approach for constructing approximate analytical solutions for one-dimensional (1D), multicomponent gas displacement problems. The solution to mass conservation equations governing 1D dispersion-free flow in which components partition between two equilibrium phases is controlled by the geometry of key tie lines. It has previously been proven that for systems with an arbitrary number of components, the key tie lines can be approximated quite accurately by a sequence of intersecting tie lines. As a result, analytical solutions can be constructed efficiently for problems with constant initial and injection compositions (Riemann problems). For fully self-sharpening systems, in which all key tie lines are connected by shocks, the analytical solutions obtained are rigorously accurate, while for systems where some key tie lines are connected by spreading waves, the analytical solutions are approximations, but accurate ones. Detailed comparison between analytical solutions with both coarse and fine grid compositional simulations indicates that even for systems with nontie-line rarefactions, approximate analytical solutions predict composition profiles far more accurately than coarse grid numerical simulations. Because of the generality of the new approach, approximate analytical solutions can be obtained for any system whose phase behavior can be modeled by an equation of state. The construction of approximate analytical solutions is shown to be orders of magnitude faster than the equivalent coarse grid compositional simulation. Hence, the new approach is valuable in areas where fast compositional solutions to Riemann problems are required.
Use of Sacrificial Agents in CO2 Foam Flooding Application
Authors: Tsau Jyun-Syung , Syahputra Andy Eka , Yaghoobi Hossein , Grigg Reid B.
Published: December 2007

This paper was prepared for presentation at the 1999 SPE Annual Technical Conference and Exhibition held in Houston, Texas, 3–6 October 1999.
A Novel Approach to Interwell Tracer Design and Field Case History
Authors: Cheung Stephen , Edwards Aimee , Howard John
Published: December 2007

This paper describes new ways to design Interwell Tracer studies and presents the successful results of a field trial conducted at the Arrowhead Grayburg Unit in Lea County, New Mexico. This is the first incidence of using existing production data to successfully design and implement an interwell tracer program as well as accurately predicting the sequence of breakthroughs. An in-house developed computer program was used to select the injection well and monitoring wells. Two tracers were injected into the injection well. One type was a novel neutralized halo-acid tracer (Isotag) and the other was a fluorescent dye, Rhodamine, to ensure that the extremely quick breakthroughs were caught. We monitored tracer breakthroughs with an in-line fluorometer system, and collected fluids with automatic samplers. The results showed that within two days, tracers broke through at one of the four wells in a five-spot pattern as well as two producers in offset patterns. Additional tracer later broke through in two of the three remaining producers in the five-spot pattern. The sequence of tracer breakthroughs was a direct correlation with the predictions. The results from this study indicated the probability of a fracture system within the reservoir, and illustrated the state of the fluid dynamics for the test area.
Implementation of a Local Grid Refinement Technique in Modeling Slanted, Undulating Horizontal and Multi-Lateral Wells
Authors: Gökta B. , Ertekin T.
Published: December 2007

Deviated holes and horizontal wells are nowadays more often exercised in developing oil and gas fields because of their potential benefits of increasing the drainage area. Recently, multi-lateral/multi-branch well technology has also been in the spotlight, especially in offshore field development projects. Forecasting the economic feasibility of deviated, horizontal, and multi-lateral wells requires a reliable and accurate representation of these wells in numerical models to mimic their expected production performances.

In this paper, we describe the implementation a local grid refinement method into a three-dimensional simulator to model flow performances of slanted, undulating horizontal, and multi-lateral/multi-branch wells. The constructed model does not utilize an equivalent wellblock radius as used in a conventional wellbore model, but utilizes the residual equation to determine the flow into the well. Physical architectures of wells are approximated as a collection of fine rectangular cells. Only the coarse blocks that are hosting wells are locally refined in all three dimensions. Fine and coarse grids are coupled, and flow equations are solved simultaneously.

The developed model provides accurate results even for early times of simulation for any wellbore architecture (slanted, undulating, multi-branch etc.) under consideration. The model does not require the computation of an equivalent wellblock radius, which may be difficult to determine accurately, especially for horizontal wells located in thin reservoirs. The proposed model can be used as a design tool in developing complex fields; for instance, to determine whether a deviated hole or an undulating horizontal well would be a better candidate in a laminated reservoir with varying vertical permeability. Another application of the model is its potential use in pressure transient analysis as it offers significant capabilities in analyzing the early time data, which contains crucial information for well test analysis.

The model results have been tested against the available analytical solutions and/or the existing numerical codes utilizing wellbore equations for vertical and horizontal wells under both sandface and flow rate specifications, and close agreements are observed. The comparison of proposed slanted well representation against existing models that employ a skin factor to represent the deviation is presented for isotropic and anisotropic systems. Applications of predicting flow performances of undulating horizontal and multi-lateral wells are also demonstrated for various systems.
Correlation of Ultra-low Shear Rate Viscosity and Dynamic Barite Sag in Invert-Emulsion Drilling Fluids
Authors: Dye William , Hemphill Terry , Gusler William , Mullen Gregory
Published: December 2007

The occurrence of barite sag has been a well recognized, but poorly understood phenomenon in the drilling industry. Problems such as lost circulation, well control and stuck pipe have resulted from the occurrence of barite sag. The financial impact of barite sag on drilling costs, usually resulting from rig-time lost while circulating and conditioning the mud system, is not trivial. There are reported incidences where recurring barite sag problems have resulted in the loss of drilling projects.

Although originally thought to occur under static conditions, barite sag is now recognized to occur more readily under dynamic, low shear rate conditions. Industry experts have offered a variety of measuring parameters, based upon empirical data, that only partially correlate with the occurrence of barite sag. The prediction of barite sag in dynamic flow has created an engineering challenge.

The effect of shear rate on dynamic barite sag, for invert-emulsion muds, has been studied and quantified using new and advanced technology. A new field viscometer, capable of measuring viscosity at shear rates of 0.0017 s-1, and an eccentric well-bore hydraulics model were used to develop and understand this relationship. Changes in mud weight as a function of shear rate, hole angle, annular velocity and eccentricity correlate with ultra-low shear rate viscosity.

Based upon experimental results, field technology has been developed to predict the potential for barite sag of invert-emulsion muds and to provide remedial measures through ultra-low shear rate viscosity modification. The efficacy of using traditional rheological measurements as indicators of barite sag potential are addressed.
Optimal Design of Two- and Three-Phase Separators: A Mathematical Programming Formulation
Authors: Grødal Evert O. , Realff Matthew J.
Published: December 2007

Oilfield primary separator units are subject to nonlinear fluid dynamic and mechanical constraints. Their design represents a challenging and important problem. In this paper we present separator design problems for which the lowest cost, optimal, solution is found using sequential quadratic programming techniques. The optimization models utilize existing separator design theories and relationships. They consist of a declarative set of equations and inequalities that is independent of the solution method and hence it is easy to make modifications and the assumptions are clear. The models are outlined and discussed in the context of horizontal separators. The efficiency and effectiveness of the suggested systematic design method are exemplified by two illustrative design cases.
A Multiscale Approach to Production Data Integration Using Streamline Models
Authors: Yoon S. , Malallah A. H. , Datta-Gupta A. , Vasco D. W. , Behrens R. A.
Published: December 2007

We propose a multiscale approach to data integration that accounts for the varying resolving power of different data types from the very outset. Starting with a very coarse description, we match the production response at the wells by recursively refining the reservoir grid. A multiphase streamline simulator is utilized for modeling fluid flow in the reservoir. The well data is then integrated using conventional geostatistics, for example sequential simulation methods. There are several advantages to our proposed approach. First, we explicitly account for the resolution of the production response by refining the grid only up to a level sufficient to match the data, avoiding over-parameterization and incorporation of artificial regularization constraints. Second, production data is integrated at a coarse-scale with fewer parameters, which makes the method significantly faster compared to direct fine-scale inversion of the production data. Third, decomposition of the inverse problem by scale greatly facilitates the convergence of iterative descent techniques to the global solution, particularly in the presence of multiple local minima. Finally, the streamline approach allows for parameter sensitivities to be computed analytically using a single simulation run and thus, further enhancing the computational speed.

The proposed approach has been applied to synthetic as well as field examples. The synthetic examples illustrate the validity of the approach and also address several key issues such as convergence of the algorithm, computational efficiency, and advantages of the multiscale approach compared to conventional methods. The field example is from the Goldsmith San Andres Unit (GSAU) in West Texas and includes multiple patterns consisting of 11 injectors and 31 producers. Using well log data and water-cut history from producing wells, we characterize the permeability distribution, thus demonstrating the feasibility of the proposed approach for large-scale field applications.
Increasing Fluid Production by Properly Venting Formation Gas in Insert Chamber Installations
Authors: Hernandez Ali , Perez Cesar , Navarro Ulbio , Lobo Williams
Published: December 2007

Accumulation chambers are generally recommended for wells with low bottom-hole pressure and high productivity index. Insert chamber is one type of accumulation chamber that is used when casing conditions do not allow the installation of double packer chambers or when lowering the point of gas injection bellow the top of the perforations will increase the liquid production.

In normal intermittent gas lift operations the formation gas is constantly being vented to the well head and no gas accumulation can occur. For insert chamber installations, formation gas has to travel downward first through the annular space between the perforation and the outside pipe of the chamber. A complicated two-phase flow process takes place in this annulus with formation gas trying to move upward and accumulate at the top, while the liquid is moving downward carrying some formation gas with it. To avoid the accumulation of formation gas in the outer annular space that can block the liquid flow from the reservoir, it is important to provide a way of venting this free gas to the surface.

Insert chambers are highly recommended in some low static pressure reservoirs located in the northern part of Lake Maracaibo where the perforated intervals are, in many cases, as long as 25% of the total depth of the wells. Unfortunately, the formation gas-liquid ratios, found in these reservoirs, are very high.

An insert chamber without a vent port for the formation gas was initially installed in Lake Maracaibo. In this case, the production was not increased. A down-hole pressure survey showed that, even though the draw-down was considerably increased, the liquid flow rate dropped drastically when only 20% of the chamber was filled. A second installation with vent port for the formation gas was installed in the same well and the production increased by 70%. A down-hole pressure survey indicated that in this case the liquid flow was considerably higher. Details of the pressure surveys and the completions installed in both cases are given in the paper, together with a simple procedure to estimate the daily production of a new insert chamber installation.