bluuebunny/crossref_metadata_2025 huggingface dataset:
Pulsed-Neutron Decay-Spectrum Data and Multi-lnflatable-Packer Plugdown Assemblies Improve Oil Production Rates
Authors: Schneider B. D. , Hogan G. P. , Holt W. N.
Published: December 2007

A gravity-stable, vertical CO2-miscible-injection flood was implemented in the 824-ft-thick Wellman Unit Wolfcamp reef reservoir in July 1983. CO2 is injected in the crest of the reservoir to displace the oil vertically downward. The producing wells are constantly plugged down out of the "gassed-out" interval into the oil bank. This paper presents the results of the PND®-S through-tubing logging tool as a method to determine the CO2/oil/water contacts and the use of multiple-inflatable-packer/sliding-sleeve plugdown assemblies to achieve zonal isolation between gassed-out and producing intervals.
Short-Radius Horizontal Drilling System Optimization in Yates Field Unit Provides Excellent Directional Control and Highly Economical Completions
Authors: Tank W. J.
Published: December 2007

Yates field unit in Pecos County, Texas, has recently drilled its 100th short-radius horizontal drainhole. The program has been a technical and economic success for the field, providing efficient completions in this highly fractured reservoir.

In the early stages of the program (1986–1990), short-radius drilling in Yates field unit was performed using strictly rotary drilling systems. In 1992, Odorisio and Curtis1 reported on the introduction of articulated downhole mud motors to the program and the impact of the initial modifications to the system. Since that time over 75 additional drainholes have been drilled. Two other drilling systems have been tested and many improvements have been made to the original system. This paper documents the optimization that has occurred in the drilling systems and the results obtained from this work.
Asphaltenes and Crude Oil Wetting—The Effect of Oil Composition
Authors: Buckley Jill S. , Liu Yu , Xie Xina , Morrow Norman R.
Published: December 2007

It is widely believed that asphaltenes and other high molecular weight, polar components of crude oils are responsible for altering the wetting of reservoir rocks, but the mechanisms by which wetting is affected are still uncertain. The concentration of asphaltenes in an oil is not necessarily a good predictor of rock/oil interactions. The composition of the remainder of the oil phase is equally important, particularly with regard to its properties as a solvent for some of its largest constituents.

Solvent quality of the crude oil mixture is a function of composition, temperature, and pressure. Changing solvent quality by addition of an excess volume of low molecular weight paraffins is the basis for definition of the asphaltenes, the material that precipitates from the diluted mixture. The extent to which wetting is altered in oil/brine/rock systems by adsorption of asphaltic material from the crude oil is affected by changes in oil solvent properties, even in mixtures in which the asphaltenes are stable with respect to precipitation.

A simple approach, using measurements of mixture refractive index, is applied to quantify oil solvent quality for mixtures of crude oil or asphaltenes with hydrocarbon additives. Wettability alteration with systematic changes in oil composition is evaluated by contact angle measurements. Crude oils generally induce greater alteration as they become poorer asphaltene solvents.
EOR Screening Criteria Revisited— Part 1: Introduction to Screening Criteria and Enhanced Recovery Field Projects
Authors: Taber J. J. , Martin F. D. , Seright R. S.
Published: December 2007

Screening criteria have been proposed for all enhanced oil recovery (EOR) methods. Data from EOR projects around the world have been examined and the optimum reservoir/oil characteristics for successful projects have been noted. The oil gravity ranges of the oils of current EOR methods have been compiled and the results are presented graphically. The proposed screening criteria are based on both field results and oil recovery mechanisms. The current state of the art for all methods is presented briefly, and relationships between them are described. Steamflooding is still the dominant EOR method. All chemical flooding has been declining, but polymers and gels are being used successfully for sweep improvement and water shutoff. Only CO2 flooding activity has increased continuously.
Gulf of Mexico Horizontal Well Improves Attic-Oil Recovery in Active Waterdrive Reservoir
Authors: Vo D. T. , Marsh E. L. , Sienkiewicz L. J. , Mueller M. D. , May R. S.
Published: December 2007

This paper presents a Gulf of Mexico field case study describing the use of horizontal wells to improve oil recovery in thin attic-oil, strong waterdrive reservoirs. Prewell planning shows the use of reservoir simulation for well performance forecasts, discusses selection of drilling mud for minimal damage, logging while drilling (LWD) for steering and optimal completion techniques. Post-well results show that horizontal wells, applied with an integration of technology, not only help accelerate production but also improve oil recovery compared with conventional wells for this type of reservoir problem.
3D Modeling To Optimize Production at the Successive Stages of Field Life
Authors: Taylor S. R.
Published: December 2007

Production optimization requires a clear understanding of subsurface conditions throughout the field's life. Description of the subsurface through classical 2D techniques is being replaced increasingly by powerful computer technology. Such technology enables construction of fully numeric 3D models of the subsurface, which can be visualized through high-end graphics displays. This 3D modeling technology is having a significant impact on development planning and monitoring activities.

The focus here is on the perceived benefits and challenges of using 3D models to optimize production. The paper includes examples of integrated 3D static and dynamic modeling activities carried out on fields undergoing appraisal and development and fields facing abandonment.

Case 1 (appraisal) illustrates how the integrated use of 3D static and dynamic modeling during primary development enables petroleum engineers (PE's) to construct alternative reservoir models rapidly and to evaluate the impact of various uncertainties quantitatively. This approach optimizes production by facilitating fast-track developments, design of robust development schemes incorporating optimized well paths, and providing quantified justification for appraisal expenditure.

Case 2 (mid field life) illustrates the benefits of using 3D modeling technology to integrate static and dynamic field data, geological knowledge, and scenario analysis concepts to locate bypassed oil and optimize infill well trajectories. History matching offers the geologist valuable feedback on the robustness of the geological model, including aspects such as the size and orientation of reservoir sands. The relative impact of various uncertainties can be quantified and development schemes optimized.

Case 3 (end field life) illustrates how, even in very mature fields that are facing abandonment, 3D modeling technology can facilitate data integration with subsequent cross-discipline interpretation. This leads to the successful planning and drilling of horizontal sidetracks to develop bypassed oil.

In all cases, the technology used allows sophisticated 3D models of the subsurface to be built through integration of diverse data types and geological knowledge. The resultant models can be upscaled rapidly for dynamic simulation; model optimization through iterative feedback from the reservoir flow simulator can be achieved easily. The facility to plan and "drill" wells in the 3D volume enables development scenarios to be optimized both in terms of well trajectory and multidisciplinary teamwork.
Determining the Parameters of the Forchheimer Equation From Pressure-Squared vs. Pseudopressure Formulations
Authors: Civan Faruk , Evans R. D.
Published: December 2007

This paper presents a comparison of the accuracy of the pressure-squared and pseudopressure formulations of the Forchheimer equation for simultaneous determination of the permeability and non-Darcy flow coefficient from high-velocity flow tests using core plugs. We show that the pressure-squared formulation must satisfy two contradictory conditions. The core length should be sufficiently small so that the average viscosity and real gas deviation factor, which are dependent on the pressure drop, approach the actual values. The core length, however, should be long enough to be representative of the characteristic length of the porous media. Because these two conditions cannot be met simultaneously, the pressure-squared formulation is less accurate. We show that these effects are more pronounced for tight formations because of higher pressure drop across the core. The pseudopressure formulation requires only that the core length should approach the representative core length, and, therefore, it provides more accurate interpretation of the high-velocity core flow tests and generates accurate values of the permeability and non-Darcy flow coefficient and the representative core length.
Development and Application of PDC Core Bits for Downhole Motor Low-Invasion Coring in the Arab Carbonates
Authors: Rathmell J. J. , Wilton B. S. , Gale B. A. , Bell D. A. , Tibbitts G. A. , Bobrosky D. J.
Published: December 2007

A method has been developed for low-invasion, downhole motor coring in the Arab formation, Arabian Gulf. Motors were used for the first time in the Arab formation to achieve higher bit rotational velocity and higher coring rate for low filtrate invasion when using a water-based mud.

Earlier, a field test of motor coring with pre-existing low-invasion core bits showed that antiwhirl core bits were superior to other core bits at high bit-rotation rates. Two new antiwhirl, low-invasion core bits with improved polycrystalline diamond compact (PDC) cutters were designed and laboratory tested for coring the Arab carbonates and anhydrites. Laboratory coring tests indicated a two-fold increase in coring rate for the new core bits with a motor compared to use of only the top drive.

The low-invasion water-based coring mud and core bits tested in the laboratory have been used to cut 278 ft of core on the Al-Rayyan field in the Qatari section of the Arabian Gulf. A downhole motor and top drive provided rotational rates at the core bit exceeding 200 rev/min compared to 100 rev/min with top drive alone. Motor coring has provided a two-fold coring-rate increase. Core quality was excellent, and core recovery was 99% with low filtrate invasion confirmed by potassium iodide tracer. Well-log and capillary pressure-derived water saturations agree with the core.
Permeability Upscaling for Near-Wellbore Heterogeneities
Authors: Soeriawinata Tono , Kasap Ekrem , Kelkar Mohan
Published: December 2007

Reservoir simulations are limited to large-scale gridblocks because of prohibitive computational costs of fine-grid simulations. Rock properties, such as permeability, are measured on a scale smaller than coarse-scale simulation gridblocks. Therefore, the properties defined on a smaller scale are upscaled to a coarser scale. Few prior studies on permeability upscaling paid special attention to the problem of radial flow in the vicinity of a wellbore. This study presents an analytical method to calculate effective permeability of a coarse-grid wellblock from its constituent fine gridblocks. The method uses the incomplete-layer upscaling procedure, which is modified for radial flow around wellbore but applied to permeability heterogeneity defined in a Cartesian grid scheme. The method is validated by numerical simulations of primary and secondary recovery processes involving two-dimensional (2D) and three-dimensional (3D) systems. The simulation results with permeabilities from radial flow upscaling for wellblocks agreed better with the simulation results with the original permeabilities than results from linear-flow upscaling.
Popeye Project: Subsea System
Authors: Ritter P. B. , Langner C. G. , Sgouros G. E. , Saucier B. J. , Voss R. K.
Published: December 2007

The subsea system installed for the Shell Offshore Inc. (SOI) Popeye project represents an advance in deepwater subsea technology. It is a diverless, guidelineless, 10,000-psi cluster-manifold concept, the first of its kind. The cluster concept was selected in large part based on SOI's deepwater experience and anticipated future subsea-development needs. This paper describes how the innovative Popeye subsea system was selected, designed, tested, and successfully installed.
Control-Volume Discretization Methods for 3D Quadrilateral Grids in Inhomogeneous, Anisotropic Reservoirs
Authors: Aavatsmark Ivar , Barkve Tor , Mannseth Trond
Published: December 2007

The paper presents a class of control-volume discretization methods for general quadrilateral grids in three space dimensions. The methods allow full permeability tensor and arbitrary orientation of the grid. The paper discusses handling of inactive cells and flow barriers. Numerical examples are used to compare the new methods with conventional corner-point geometry methods.
Multilateral Horizontal Well Increases Liquids Recovery in the Gulf of Thailand
Authors: Horn M. J. , Plathey D. P. , Ibrahim Ouahiba
Published: December 2007

This paper describes the objectives, the completion, and the first results of the dual-horizontal Well BK-4-M, which was drilled in May 1996 in the Bongkot field. The main objective of Well BK-4-M was to maximize the recovery from a shallow and thin oil rim by delaying the water breakthrough by 2 years and by maintaining a flow rate of 4,000 B/D. Compared with a conventional deviated well, the final recovery will increase by three times. The completion of Well BK-4-M was a challenge in terms of technical and economic planning. Well BK-4-M was put on stream successfully in July 1996 with a potential flow rate of 4,000 B/D. The duration of operations was 21 days, including completion. Each of the two horizontal branches has a length of approximately 1000 m and is located in the upper third of the 10-m-thick oil rim. The cost of Well BK-4-M was 1.70 times higher than a conventional single-drain deviated well, and the well is expected to triple recovery by using only one platform slot. It is the first dual-horizontal well ever completed in Southeast Asia.
Increasing Coal Absolute Permeability in the San Juan Basin Fruitland Formation
Authors: Mavor M. J. , Vaughn J. E.
Published: December 2007

Recently measured data show that the absolute permeability of coal natural fracture is increasing significantly with continued gas production in the San Juan basin Fruitland formation. This phenomenon caused gas-production rates to be many times greater than expected from early production history. The phenomenon also caused producing bottomhole pressures to increase when gas rates were constant, opposite from that expected from conventional applications of Darcy's law.

The increase in absolute permeability caused by gas desorption has been measured on cores,1–3 but, until recently,4 there was no verification that this phenomenon occurs in situ. Palmer and Mansoori4 (P&M) presented a new theory and showed how this theory matched gas- and water-production rates and estimated bottom-hole-pressure data for a high-deliverability San Juan basin Fruitland formation coal-gas well. However, Palmer and Mansoori4 had no transient pressure data to support in-situ permeability changes. This paper documents data from drillstem tests (DST's) and shut-in tests with analyses thereof and additional production-rate and pressure behaviors that support the P&M theory.

The well-test data were measured in three wells completed in the San Juan basin Fruitland formation coal seams located under the Valencia Canyon (VC) area. These wells, VC 29-4, VC 32-1, and VC 32-4, are located in Sections 29 and 32, T33N, R11W, La Plata County, Colorado, and operated by EnerVest San Juan Operating LLC. In addition to the well-test data, EnerVest and the Gas Research Inst. (GRI) collected extensive formation-evaluation data and performed detailed analyses that allowed a thorough description of the area. Although there are other wells operated by EnerVest in the area, well-test data were not available from the other wells to determine the absolute permeability estimates; therefore, these wells are not discussed in this paper.

The P&M theory was calibrated with well-test-derived absolute permeability estimates and published coal-shrinkage data.5 Reservoir simulation models, based on the calibrated theory, matched the unusual producing, bottomhole-pressure behavior. Without the P&M theory it was not possible to match pressure behavior or permeability estimates with reasonable variations of reservoirproperties input into the reservoir-simulation models.

The remainder of this paper summarizes the well-test analysis results from the three wells and, for brevity, one set of well-test data and one simulation study. The well-test data and simulation studies for the other wells were similar to the examples.
Optimization of Pipeline Networks With a Hybrid MCST-CD Networking Model
Authors: Sung Wonmo , Huh Daegee , Lee Junghwan , Kwon Oukwang
Published: December 2007

In this paper, we present a hybrid network model (HY-PIPENET) that uses a minimum cost spanning tree (MCST) network algorithm to determine the optimum path and constrained derivative (CD) method, to select an optimum pipe diameter. The HY-PIPENET has been validated with the published data of a six-node/seven-pipe networking system, and, moreover, this system has been optimized with the MCST-CD method. As a result, it was determined that the gas can be sufficiently supplied at a lower pressure with smaller diameters of pipe, compared to the original system in a six-node/seven-pipe network. Hence, the construction cost was reduced about 40% in the optimized system. The hybrid networking model has also been applied to a complicated domestic gas pipeline network in a metropolitan area of Korea. In this simulation, a parametric study was performed to understand the role of each individual parameter such as the source pressure, flow rate, and pipe diameter on the optimized network. From the results of these simulations, we have proposed that the optimized network is a tree-type structure with an optimum pipe diameter and source pressure, which was used in a Korean metropolitan area. This proposed system however, does not consider potential environmental problems as well as safety concerns.
Laboratory Studies for Light-Oil Air Injection Projects: Potential Application in Handil Field
Authors: Clara Cédric , Durandeau Marc , Quenault Gérard , Nguyen Tuyêt-Hang
Published: December 2007

Air injection into light-oil reservoirs is now a proven field technique. Because of the unlimited availability and the nil access cost of the injectant, the application potential of this improved recovery process is promising when associated with the lack of available hydrocarbon gas sources for injection. One of the keys of a successful air injection project is the evaluation of the process by carrying out representative laboratory studies. Therefore, an original laboratory strategy was proposed to assess the recovery potential by air injection into light-oil reservoirs, and to help the determination and the quantification of optimal operating conditions.

In this paper, the air injection technique applied to light-oil reservoirs is explained. Then, the laboratory strategy proposed for the evaluation of an air injection project is described, and the experimental objectives, devices, and procedures are explained. In order to provide reliable experimental data, high-pressure and high-temperature experiments (up to 40 MPa and 500°C) are performed with consolidated reservoir cores and reservoir oils, at representative conditions of the air injection process in light-oil reservoirs.

Finally, a laboratory evaluation regarding a potential application for an air injection pilot in the Handil field (Mahakam delta, Indonesia) is presented and discussed.
Identification of Unknown Permeability Trends From History Matching of Production Data
Authors: Grimstad Alv-Arne , Mannseth Trond , Aanonsen Sigurd Ivar , Aavatsmark Ivar , Cominelli Alberto , Mantica Stefano
Published: December 2007

We investigate how a priori unknown large-scale permeability structures such as channels or barriers can be identified from history matching of production data, using Adaptive Multiscale Estimation (AME).

With Multiscale Estimation (ME) of the permeability, we solve a sequence of parameter estimation problems with increasing resolution for the permeability until a match is obtained. With AME—and contrary to Ordinary Multiscale Estimation (OME)—the parameterization refinement is not the same all over the reservoir. We aim at introducing new degrees of freedom in the permeability parameterization only where it is warranted by the production data.

The paper describes the principles of AME and extends AME to corner-point grids on nonrectangular 2D reservoirs. On 2D synthetic examples with simplistic geometry, we demonstrate how AME is able to completely identify simply shaped large-scale permeability trends and how it avoids overparameterization.

On 2D synthetic examples with more complex geometry (field-scale synthetic examples), AME is found to identify large-scale trends. When the large-scale trend has a more complex shape, AME identifies a similar trend of less complex shape at approximately the same location. The identification of the permeability trends for the field-scale synthetic examples can, however, be improved upon, and, for example, use of coarsening (as well as refinement) in the parameterization selection will be further considered in future work.
A New Technique to Solve Gas Hydrate Problems in Subsea Christmas Trees
Authors: Marques L. C. C. , Pedroso C. A. , Neumann L. F.
Published: December 2007

The paper is aimed at describing the series of actions taken to re-enter a well, the (wet) Christmas-tree cap of which was clogged by solid hydrate and therefore could not be released by means of a regular releasing tool. A deepwater well located in Campos Basin, offshore Rio de Janeiro, Brazil, was the location for this unique job. To our best understanding, the kind of approach used to solve this hydrate problem had never been used in the industry before.

A patented thermochemical method—the so-called self-generated nitrogen (SGN) method—was applied to heat and dissociate the crystallized hydrate, which was clogging the piston chamber of the tree-cap locking pin. Heat application around the body of the Christmas tree enabled us to dissociate the hydrate and release the tree cap by means of its regular retrieving tool.

This paper describes all the steps taken to perform this pioneer workover job. As a matter of fact, it was a multidisciplinary task that encompassed the following points:

- Development of a "tailor-made" environmentally friendly SGN formulation.

- Heat exchange simulations to design the optimum volume for the SGN treatment batch.

- A review of the theoretical aspects of hydrate formation/dissociation.

- Mechanical modifications of the (regular) tree cap releasing tool.

- A meticulous review of the job and safety procedures.
Imaging Unstable Wellbores While Drilling
Authors: Edwards S. , Matsutsuyu B. , Willson S.
Published: December 2007

This paper presents a case study of borehole instability from four wellbores on the Gulf of Mexico (GOM) shelf, offshore Louisiana. Logging-while-drilling (LWD) borehole images are combined with observations of cavings and modeling of borehole shear failure to diagnose the mechanisms of instability and, thus, select the appropriate remedial action.

It is observed that instability caused by shear failure of intact rock (borehole breakout) can be suppressed by increasing the MW. However, where pre-existing planes of weakness (such as bedding planes and fractures) dominate the mechanism of instability, mudweight increases do not necessarily lead to a more stable hole and can, in fact, further destabilize the wellbore.
Removal of Water-Soluble Organics From Produced Brine Without Scale Formation
Authors: Hart Paul R.
Published: December 2007

Water-soluble organics (WSOs) are included in the measurement of oil and grease (O&G), a conventional pollutant controlled by the Clean Water Act. WSOs partition to the produced brine at the production pH, but to the extraction solvent used to measure the O&G at the test pH of <2. The predominant chemical species comprising WSOs in Gulf of Mexico crude oil brines are medium-chain carboxylic acids. Chemicals can be added to desolubilize these species in conjunction with treatments to remove the resultant emulsion. For a variety of reasons, the most reliable and cost-effective desolubilization agents have proven to be the nonvolatile, multiprotic oxo acids (e.g., HxSOx and HxPOx). However, in the presence of many common divalent cations in the brine, these form insoluble scale deposits. Moreover, in the presence of WSOs in mixed production, this scale becomes oil-wet and uninhibitable. A new treatment comprising a new class of desolubilizer in conjunction with certain polymers has now been shown to be equally reliable and cost-effective without the formation of scale, even at extreme concentrations of divalent cations. The chemistry is explained and case histories chronicled to illustrate its effectiveness in the field.
A Method for Isolating Pressure-Depleted Zones With Solid-Expandable Tubulars
Authors: Moore Melvin J. , Wright Jon C. , Winters Warren J. , Daigle Chan
Published: December 2007

A method for installing solid-expandable-tubular (SET) drilling liners across pressure-depleted zones has been developed and demonstrated. High overbalance pressures are known to interfere with conventional SET expansion. "Scoping" allows an expandable liner to expand and move downward while the inner work string and expansion cone remain still. This expansion method keeps the expandable liner in continuous motion, thus reducing the risk of stuck pipe and SET failures related to differential sticking.

The most common expansion method involves deployment of an SET liner on an expansion cone assembly connected to a work string. The SET is run to within 5 to 10 ft of the well bottom, then expanded hydraulically from the bottom upward. Initially, the expansion cone remains stationary when the liner is hydraulically pushed downward while expanding. The expanded liner stops advancing when it reaches bottom, and then the cone is hydraulically pushed upward as it continues to expand the liner.

Scoping differs from standard expansion in that the expansion cone is initially positioned far off-bottom in the open hole between the previous casing shoe and the depleted zone. The liner is then extruded off the expansion-cone face, literally pumping the expanded liner to the bottom. The continuous movement of the expanded casing across the depleted zone reduces the risk of differential sticking. A purpose-built scoping shoe permits cementing after the pipe expansion on the same trip.

This paper describes how scoping is performed and how it worked in a test well. Advantages (including time savings) and practical limitations are discussed. Additionally, the scoping shoe introduces new efficiencies to SET deployment, even if scoping is not used.
Organic Acids in Carbonate Acidizing
Authors: Buijse Marten , de Boer Peter , Breukel Bert , Burgos Gerardo
Published: December 2007

This paper discusses the use of organic acid as a stimulation fluid in carbonate formations. Organic acids, such as acetic or formic acid, have been used for many years as alternatives to HCl because of the retarded reaction rate, low corrosivity, and reduced tendency to form acid/oil sludge in asphaltene-rich crudes. In Venezuela, organic acids were pumped in acid-fracturing treatments in deep, hot limestone formations. Although these treatments were very successful, optimization of the design was hampered by the fact that models for organic acid/carbonate spending did not exist. Case histories are discussed later.

A new model for acid spending is proposed in this paper that can be used for strong (HCl) and weak (organic) acids as well as acid mixtures. Compared to existing (HCl) models, the only new element is the acid dissociation constant that describes the differences between strong and weak acids. The model was verified by comparing simulated reaction rates with rates actually measured in the laboratory with a rotating disk. The results of acid-fracture simulations, comparing the etched length and width of organic acid with HCl acid, are also discussed.
Experimental Study of Gas Injection in a Surfactant-Alternating-Gas Foam Process
Authors: Xu Q. , Rossen W. R.
Published: December 2007

Fractional-flow methods have been shown to be accurate and successful in modeling surfactant-alternating-gas (SAG) foam processes. Fractional-flow theory indicates that the success of gas diversion in a SAG process depends on steady-state foam behavior at very low water fractional flow fw (very high foam quality). Previous simulation studies of these processes have relied on extrapolating steady-state data taken at much higher values of fw. Radically different results are predicted depending on how these extrapolations are made. Data are needed at very low fw to predict SAG performance in the field.

Laboratory coreflood experiments were conducted to obtain the needed fractional-flow curves. For each value of fw, constant water- and gas-injection rates were imposed and maintained until the system reached steady state. The corresponding average water saturation in the core was determined by weighing the core continuously during the experiment. Experimental fractional-flow curves are presented for two surfactant formulations in Berea sandstone core, with no oil present, at extremely high foam quality.

Results are then scaled up using fractional-flow theory to a hypothetical field-scale application. In both cases, the data scale up to successful mobility control on the field scale. In one case, foam suffered an abrupt decline from stronger foam to coarser foam with increasing foam quality, with a multivalued fractional-flow function, in agreement with some earlier experimental and theoretical results.
Specific Fluid Requirements for Successful Coiled-Tubing Fracturing Applications
Authors: Cawiezel Kay E. , Wheeler Richard S. , Vaughn David R.
Published: December 2007

The recent success of coiled-tubing fracturing in shallow wells has increased interest in using coiled tubing for fracturing deeper and hotter wells. Industry efforts now need to focus on understanding what properties a fracturing fluid must possess to carry proppant successfully at high rates through coiled tubing, frac ports, and perforations and into these deeper formations. The key performance requirements of a coiled-tubing fracturing fluid for deeper wells are low frictional pressure loss and adequate proppant-carrying capability after exposure to high-shear zones and high temperatures.

This paper summarizes the results of pilot- and field-scale testing that led to the development of an optimized coiled-tubing fracturing fluid. Results show that polymer-based fracturing fluids can be controllably delayed to have low frictional pressure loss through the curved coiled-tubing unit and straight tubing. However, results also show that fluid stability can be reduced significantly when the fluid is pumped through small-diameter tubing followed by high-shear zones such as frac ports and then by perforations. Results demonstrate that correct fluid choice and fluid optimization are required to meet proppant-transport requirements. For coiled-tubing fracturing to be successful, the fluid and treatment-design recommendations should balance frictional-pressure-loss limitations with fluid-stability limitations.
Experimental and Theoretical Simulation of Gravel-Pack Displacement in Extended Horizontal-Offshore Wells
Authors: Martins A. L. , de Magalhães J. V. M. , Calderon A. , Mathis S. P. , Trujillo C. , Nguyen H. T.
Published: December 2007

This article presents the development of a computational tool to guide horizontal gravel-pack design for long horizontal offshore wells. Mechanistic model hypotheses, experimentation at a large-scale flow loop, and software development are detailed. The computer simulation results are then compared with field data collected in the Campos basin operations, offshore Brazil. A discussion on design alternatives for a long horizontal well at low fracture-gradient formations is presented. This discussion includes a sensibility analysis on screen eccentricity, open and closed blowout-preventer(BOP) configurations, and alpha (alone) vs. alpha plus beta wave displacement options.
Drilling Salt Formations Offshore With Seawater Can Significantly Reduce Well Costs
Authors: Willson Stephen M. , Driscoll Peter M. , Judzis Arnis , Black Alan D. , Martin J. Wesley , Ehgartner Brian L. , Hinkebein Tom E.
Published: December 2007

The rate of penetration (ROP) increases significantly if salt formations are drilled with undersaturated fluids. This is especially true when drilling riserless. Of primary concern is the amount of hole enlargement that will occur. However, if managed, then a step change in drilling performance and costs can be achieved.

This paper presents in detail the results of a comprehensive and large-scale laboratory testing program performed on outcrop salt samples that replicate drilling salt formations with undersaturated drilling fluids with flow rates of up to 1,000 gal/min (gpm). The laboratory testing program includes tests performed in a computerized tomographic (CT) scanner to map hole enlargement in real time, as well as variously sized borehole leaching tests with borehole diameters of up to 6 in. Flow rates are scaled to produce comparable levels of turbulence occurring in the field.

An analytical hole-enlargement prediction model is presented that incorporates the effects of ROP, pump rate, drill-fluid saturation, dissolving salt drill cuttings, and salt leaching from the borehole wall. This model accurately predicts to within 10% the measured hole enlargements produced in the scaled laboratory tests for a wide range of flow rates and fluid saturations.

Predictions of field performance are made, and the implications of the predicted hole geometry are discussed. Provided that high rates of penetration are realized, acceptable hole geometries will result, even when pumping seawater at flow rates of up to 1,600 gpm. A field application is described whereby the historical practice of drilling the last 200 ft of the 20-in. hole into salt using a saturated brine drilling fluid was discontinued in preference to the continued use of seawater. The competing influences of increasing rate of penetration and avoiding the cost of a sacrificial mud system, offset by the increased cost of cement, resulted in cost savings of U.S. $250,000 per well. Implemented in a multiwell subsalt development, cost savings of more than U.S. $1.5 million will be realized in the drilling program. Further applications of this technology are now being sought.
Horizontal Drilling and Openhole Gravel Packing with Oil-Based Fluids-An Industry Milestone
Authors: Wagner M. , Webb T. , Maharaj M. , Twynam A. , Green T. , Salamat G. , Parlar M.
Published: December 2007

An increasing number of horizontal wells requiring sand control are being gravel packed, particularly in deepwater and/or subsea environments in which completion reliability is paramount because of the prohibitively high cost of remediation. Tophole sections in many of these wells are being drilled with oil-based (OB) fluids, with the common practice of switching to water-based fluids when the reservoir drilling starts. In the last several years, some operators started using OB drilling fluids in the reservoir section as well and gravel packed them with water-based fluids. In some cases, these practices required running predrilled liners in OB fluids and subsequently displacing to water-based fluids before running in hole with the sandface screens and gravel packing. In other instances, screens could be run in hole with OB fluids in the wellbore, and gravel packing could be performed with water-based fluids. In both cases, the presence of reactive shales and/or water-sensitive productive zones can introduce serious concern, in the event that carrier-fluid losses occur into the formation during gravel packing. Although a base-oil or diesel can be used as a carrier fluid, low density of the base oil limits such applications to low-pressure/depleted wells.

In this paper, we present a case history of the first successful application of drilling and completing in an all-oil environment, using a reversible OB reservoir-drilling fluid (RDF) (the filter cake of which reverses wettability from oil to water when exposed to an acidic fluid) and an OB gravel-packing fluid. The carrier fluid used in this application included a filter-cake cleanup solution in the aqueous internal phase of the OB carrier fluid, extending the application of simultaneous gravel-packing and cake-cleanup processes that have been successfully practiced in water-based-fluid environments to OB systems. The subject application was in a high-rate gas field located offshore Trinidad, with anticipated production rates in excess of 150 MM scf/D per well. Presented in the paper is the drilling and completion selection methodology based on extensive laboratory and yard testing, along with the details of the completion and recommendations for future applications based on lessons learned. A direct comparison of the all-oil drilling and completion process to water-based drilling and completion is also presented based on a case history from the same field.
The Shortcomings and Challenges of Metering–System Automation in the Petroleum Industry
Authors: Ogwo O. U. J.
Published: December 2007

Since about 1990, the automation of flowmetering systems has been gaining momentum. During this time, operations have been simplified by flow-system automation, but the petroleum industry has been exposed to significant fiscal losses arising from "teething problems." This paper reviews the problems that are yet to be addressed by the automation industry, based on field experience over an extended period of time. The fiscal significance of these shortcomings is presented, and measures are suggested to correct the problems. It is expected that this work will prompt the automation industry to address the existing limitations of metering systems when designing future flow computers.
Oil-Viscosity Predictions From Low-Field NMR Measurements
Authors: Bryan J. , Kantzas A. , Bellehumeur C.
Published: December 2007

Canada contains vast reserves of heavy oil and bitumen. Viscosity determination is key to the successful recovery of this oil, and low-field nuclear magnetic resonance (NMR) shows great potential as a tool for estimating this property. An NMR viscosity correlation previously had been developed that is valid for order-of-magnitude estimates over a wide range of viscosities and temperatures. This correlation was built phenomenologically, using experiments relating NMR spectra to viscosity. The present work details a more thorough investigation into oil viscosity and NMR, thus providing a theoretical justification for the proposed correlation. A novel tuning procedure is also presented, whereby the correlation is fitted using the Arrhenius relationship to improve the NMR viscosity estimates for single oils at multiple temperatures. Tuning allows for NMR to be potentially used in observation wells to monitor thermal enhanced oil recovery (EOR) projects or online to monitor the viscosity of produced-fluid streams as they cool.
The Potential Role of Passive Seismic Monitoring for Real-Time 4D Reservoir Characterization
Authors: Maxwell S. C. , Urbancic T. I.
Published: December 2007

This paper details the application of passive seismic monitoring to image reservoir fracturing and deformation from the stage of an initial well completion to final field production. Instrumented oil fields with seismic arrays either permanently installed or temporarily deployed on wireline offer the possibility of imaging production activities in a real-time sense that complements other seismic reflection and engineering measurements. During the well-completion stage of development, real-time microseismic imaging offers the possibility of monitoring well stimulation. Fracture images may be used to optimize the fracture design and the net present value (NPV) of well production, as well as understand fracture complexity and the associated well-drainage pattern to target future well placement. During production stages, time-lapse microseismic imaging may be used for image deformation associated with fracturing or fracture reactivation from pressure or stress changes, strains in the overburden in fields with casing-deformation problems, and image fronts associated with secondary recovery. In this paper, several case studies are used to illustrate various potential applications, along with discussion of the potential limitations. The reservoir conditions necessary for the success ful application of the technology are presented along with a potential method to quantify the technical feasibility at a particular site.
Polymer Gels Formulated With a Combination of High-and Low-Molecular-Weight Polymers Provide Improved Performance for Water-Shutoff Treatments of Fractured Production Wells
Authors: Sydansk R. D. , Al-Dhafeeri A. M. , Xiong Y. , Seright R. S.
Published: December 2007

A laboratory study has shown improved performance for fracture-problem water-shutoff polymer gels that are formulated with a combination of high-and low-molecular-weight (MW) polymers. These gels are intended for application to fractures or other high-permeability anomalies that are in direct contact with petroleum production wells. More specifically, we focused on evaluating the mechanical strength and improved performance of these water-shutoff gels for use when exceptionally large fracture apertures or large drawdown pressures are encountered. During our study, the gels were injected into laboratory-scale fractures while the gel was in a partially formed state. The flooding-experiment study involved the placement of partially formed chromium(III)carboxylate/acrylamide-polymer (CC/AP) gels in 1-to 4-mm (0.04-to 0.16-in.) apertures, by 2-ft-long × 1.5-in.-height fractures where the fracture walls were 700-md unfired Berea sandstone.

During the injection of a 1.5% high-MW and 2.0% low-MW polymer-gel formulation, the partially formed gel fluid exhibited an effective viscosity of approximately 500 cp during placement in a 1-mm (0.04-in.) -aperture fracture, and the matured gel exhibited exceptionally good fracture-plugging characteristics. The gel withstood 52-psi total differential pressure across the fracture length (26-psi/ft pressure gradient) for 24 hours, while permitting no detectable brine flow through the gel-filled fracture. Subsequently, when the differential pressure was increased to 175 psi (88-psi/ft pressure gradient), the gel rendered a brine permeability-reduction factor in the fracture of 30,000. When placed in a 4-mm (0.16-in.)aperture fracture, a 25-psi/ft critical pressure gradient was required to render first and limited brine flow through the fracture containing gel of the same composition. After exceeding the critical pressure gradient, the stabilized permeability-reduction factor imparted by the gel to brine flow in the fracture was 260,000. When increasing the brine flow rate through a gel-containing 4-mm fracture from 500 to 8,000 cm3/hr (superficial velocities of 260 to 4,100 ft/d in the open fracture), the stabilized permeability-reduction factor decreased from 100,000 to 39,000.

The high-and low-MW CC/AP gels exhibited disproportionate permeability-reduction (DPR) effects during oil and brine flow through gel-filled fractures. However, the gels of this study are probably better characterized as total-shutoff or sealing agents (not DPR agents) because of the large permeability reduction imparted to oil flow through the gel-filled fractures.
Oil/Water Separation Experience From a Large Oil Field
Authors: Kokal Sunil , Al-Ghamdi Abdullah
Published: December 2007

This paper discusses challenges related to emulsions that have been encountered in a large Saudi Arabian field. The field produces from several different reservoirs with a range of fluid properties. These properties provide an interesting case of operational challenges in oil/water separation, including increased incidents of shorting in the separator, tripping of equipment, and increased demulsifier consumption.

This paper presents the results of a comprehensive study that was initiated to understand the main causes of emulsion formation in the field and ways to optimize oil/water separation. The effects of several recommendations that were implemented by operations engineering in the field were evaluated. These include the conversion of a two-phase separator into a three-phase separator, splitting of the demulsifier injection between offshore producing platforms and onshore wet-crude handling facilities, and field trials with promising chemicals. The demulsifier costs have been reduced by more than 50% by the implementation of retrofitting and proper demulsifier-injection strategies. The results presented in the paper provide invaluable operational experience, and many lessons learned are applicable to any crude-oil-treating facility.
The Penetration of Coiled Tubing With Residual Bend in Extended-Reach Wells
Authors: Zheng Andrew , Adnan Sarmad
Published: December 2007

Residual bend exists in every coiled tubing string. When the coiled tubing is placed inside a wellbore, its initial configuration is not straight but has a certain residual bend. This paper's objective is to explain how this residual bend in coiled tubing affects its extended reach.

This paper presents a new modeling technique to account for the effect of residual bend on coiled-tubing posthelical buckling behavior and maximum penetration. The initial configuration of the coiled tubing is assumed to be the form of a helix along the wellbore. By using the energy method, a set of solutions is obtained for the helix configuration and the radial contact force under the conditions of applied axial force and initial residual bend. These solutions are used to analyze axial load transfer and extended-reach capability of coiled tubing on horizontal wells. It is shown that in a horizontal well, with a relatively small residual bend radius, the existence of residual bend significantly reduces the maximum depth the coiled tubing can reach. Results of this work can be used to enhance job design for extended-reach applications.
Phase Behavior of Athabasca Vacuum Bottoms + n-Alkane Mixtures
Authors: Zou Xiangyang , Zhang Xiaohui , Shaw John M.
Published: December 2007

The phase behavior of Athabasca vacuum bottoms (ABVB), a 798.15+K (525+°C) boiling fraction comprising 32 wt% pentane asphaltenes +pentane mixtures, is elucidated using x-ray transmission tomography. These pseudobinary mixtures are models for the development of novel heavy-oil/bitumen production and refining processes. Depending on their overall composition, these mixtures are shown to exhibit three- and four-phase equilibria, including both expected (L1L2V) and unexpected (L2L3V) phase behavior separated by a small L1L2L3V zone. These multiphase equilibria provide challenges in production environments, where miscible flooding is typically desired, but afford new opportunities for the development of separation technologies in refining. Example phase diagrams are presented (pressure-temperature at constant composition and pressure-composition at constant temperature), which focus on the bubble pressure region where multiphase regions arise. Limited phase equilibria data sets for ABVB+heptane, decane, and dodecane are also presented so that trends for ABVB+alkane mixtures with the size of the alkane diluent can be explored. It is expected that these phase diagrams will provide useful insights to heavy-oil producers and refiners, in addition to providing a benchmark for testing phase-behavior models for these and related complex hydrocarbon mixtures.