bluuebunny/crossref_metadata_2025 huggingface dataset:
Slug-Tracking Model for Hilly Terrain Pipelines
Authors: Taitel Yehuda , Barnea Dvora
Published: December 2007

Slug flow is a very common occurrence in gas-liquid two-phase flow. Usually, it is an unfavorable flow pattern due to its unsteady nature, intermittency, and high-pressure drop.

A hilly terrain pipeline consists of horizontal, uphill, and downhill sections. While slug flow is relatively well understood for any of the three configurations, there is a lack of understanding of how flow characteristics change when these configurations are interconnected, as in a hilly terrain pipeline.

Almost all-previous slug flow studies assume a constant slug length once a slug is formed and developed into a stable slug. In reality, a slug can grow or shrink as it travels through a pipeline as a consequence of the hilly terrain configuration. In addition, slugs can be generated at low "elbows" and dissipate at top "elbows." An experimental study conducted by Zheng et al.1 and Zheng2 clearly demonstrates the effect of hilly terrain pipeline configuration on slug characteristics.

In the present work slug behavior in low and top elbows is simulated and studied. The effect of compressibility is included.
Computer Log Analysis Plus Core Analysis Equals Improved Formation Evaluation in West Howard-Glasscock Unit
Authors: Wilson D.A. , Hensel W.M.
Published: December 2007

This paper describes an orderly and systematic approach to the solution of a parameter identification problem in a West Texas carbonate reservoir. A well-planned coring program and subsequent conventional and special core analysis provide a sound basis for computer log analysis of the complex lithology of the San Andres formation.

Introduction

The Howard-Glasscock field is located south of Big Spring, Tex., in Howard and Glasscock counties, and has produced oil from the Lower Grayburg and San Andres formations since 1929. Sun Oil Co. began pilot waterflooding on the Hart-Phillips lease in 1964. The West Howard-Glasscock Unit was formed Jan. 1, 1972. During 1973, 40 wells were drilled for waterflood expansion. Ten wells were cored extensively and 38 wells were logged with suites designed for computer analysis. Fig. 1 shows the distribution of the cored and logged wells. Approximately 80 wells existed before this project and are not shown.

Coring Program

Because of the complex lithology associated with the producing formations, an extensive coring program was conducted to aid in log interpretation, geological mapping, and injection-well planning. The 10-well coring program is summarized in Table 1. The over-all recovery efficiency was 98.2 percent, with a core loss of only 73 ft occurring during the 4,118-ft coring. Of the unrecovered 73 ft, 52 ft were lost on one well, which increased the core recovery efficiency of nine wells to 99.4 percent. Recovery efficiency contributed immeasureably to the log interpretation program because core-analysis values could be correlated directly with log-derived values without the usual large gaps in core footage.

Basic Core Analysis

The cores were transported to a service company laboratory and analyzed by "whole-core" techniques. The whole-core technique1 analyzes various lengths of full diameter core for fluid saturations, porosity, and two-directional horizontal permeability (kmax and k90°). Whole-core analysis was selected because the heterogeneous nature of the San Andres precludes representative sampling by plug-type core-analysis techniques. Selection of samples for plug-type core-analysis techniques will be discussed later. A total of 1,516 whole-core sections were analyzed. Based on a total recovery of 4,045 ft, approximately two-thirds of the cores were nonreservoir rock, such as shale and anhydrite.
The Marsh Funnel and Drilling Fluid Viscosity: A New Equation for Field Use
Authors: Pitt M. J.
Published: December 2007

The flow behavior of a Marsh funnel was numerically simulated for power law fluids and was found to give good agreement with experimental measurements. As a result, the simulation provides a general picture of the meaning of the Marsh funnel time and a correlation enabling this to be converted into a value for effective viscosity of non-Newtonian fluids. For field use, the following equation relates the effective viscosity μe (cp) to the Marsh funnel (quart) time t (seconds) and the density ρ (g/cm−3) μe = ρ (t-25).
Unique ESP Completion and Perforation Method Maximizes Production in World Record Step-Out Well
Authors: Blosser W. R. , Davies J. E. , Newberry P. S. , Hardman K. A.
Published: December 2007

In this article we describe the key planning and operational experiences gained during the perforation and completion phases of the world record step-out extended reach well at the Wytch Farm oilfield in Dorset, England. We present an overview of how the M-11 well was completed successfully and describe how a combination of existing and new technology was applied to achieve Wytch Farm's most prolific producer.

Well 1M-11SPy (M-11) the world record for the highest horizontal departure, 10 114 m, at any vertical depth, and a record departure to true vertical depth ratio of 6.24. The Wytch Farm extended reach wells are completed with cemented, perforated liners and electrical submersible pumps (ESP's).

A new technique for perforating the well was developed to maximize inflow efficiency. This technique enables underbalance perforating without any subsequent requirement for a well kill. The impact of these improvements on completion efficiency is discussed, along with associated operational issues.

The large departure required the ESP to be set at 8625 m, another world record, with the 1,000 HP motor requiring a new 7 kV cable system and a 1500 kVA variable speed controller (VSC) at the surface. We describe the VSC selection and the physical testing of the complete ESP/cable/VSC system, which was conducted before installation to ensure that sufficient torque could be generated at the ESP for a range of startup and operating conditions and to configure the new type of VSC used for optimal system performance. We also report the experience gained and review the lessons learned.
Optimization of Mud Cleanup for Openhole Horizontal Wells
Authors: Morgenthaler L. N. , McNeil R. I. , Faircloth R. J. , Collins A. L. , Davis C. L.
Published: December 2007

Successful completion of openhole horizontal wells requires removal of potential impairment from the near wellbore and formation face. Impairment can reduce well productivity and lead to failure of sand control screens due to plugging and erosion. Shell has adopted the practice in the Gulf of Mexico of employing drill-in fluids with acid-soluble bridging and weighting agents for all openhole drilling and extensive displacement and acid cleanup procedures during horizontal well completions. Drill-in fluid and filtercakes are removed with specially formulated sweeps and by attainment of sufficient velocity to achieve effective displacement. Filtercakes are removed with specially formulated washes applied using washcups or coil tubing to ensure that the cleanup formulations contact the filtercake materials.

Drill-in fluids and cleanup systems must be specially formulated and evaluated for specific applications. We have adopted a suite of laboratory screening tests to evaluate formation damage and removal chemistries to ensure that each well is effectively cleaned. These tests can also be used to evaluate new fluid systems before taking them to the field. Our approach in this instance is to compare data from new fluids to results obtained with fluids with which we have a successful field track record. In this article we will review these procedures and the results with a variety of fluid systems.
Barite Sag: Measurement, Modeling, and Management
Authors: Bern P. A. , van Oort Eric , Neustadt Beatrice , Ebeltoft Hege , Zurdo Christian , Zamora Mario , Slater K. S.
Published: December 2007

A joint industry project was established to study barite sag mechanisms and to develop field guidelines to manage the consequences. A simple empirical model was developed to compare sag potential for a wide range of fluid types. In the study, physical properties of the mud, wellbore conditions, and characteristics of the weighting material were shown to have a large influence on sag behavior. The study also included direct measurements of the properties of settled weight-material beds. These results provide new insight into the mechanisms of barite sag and how best to manage problems in the field.

Data from the tests clearly demonstrate that the parameters affecting sag are interrelated and seldom act in isolation. For all muds tested, the highest sag occurred at low annular velocities over angles from 60 to 75°. Drillpipe rotation was particularly beneficial in minimizing barite settlement. Rotation also assisted in re-distributing barite deposits formed on the low side of the hole.

The improved understanding of the mechanisms of barite sag enabled development of practical field guidelines. Case history studies presented in the paper demonstrate how the results of the work together with better field monitoring have been successfully applied to manage the effects of barite sag in high-pressure/high-temperature and extended-reach drilling operations.
Coiled-Tubing Surface Characteristics and Effects on Fatigue Behavior
Authors: Tipton S. M.
Published: December 2007

The manufacturing procedure for coiled tubing induces different surface morphologies on the inner and outer surfaces. Since fatigue is a surface phenomenon, this can lead to different fatigue behavior at the two locations. This has been demonstrated in full-scale bending tests and in axial tests conducted on small coupon samples in closed-loop servohydraulic strain control. Furthermore, service environments can cause localized defects on the outer and inner surfaces of coiled tubing, such as grinding marks, corrosion pits, tool marks, or injector block damage, which can have a first order effect on fatigue strength. However, it is demonstrated in this article that there is an inherent tendency for cracks to initiate on the inner surface of coiled tubing. This tendency leads to the hypothesis that a "threshold severity" for external surface defects could exist, below which the fatigue strength of the tubing is not affected. Limited data confirm this hypothesis, and suggest that the severity could depend on the grade of the material.
Building a System in a Service Company To Assure Technical Integrity and Institutionalize Organizational Learning
Authors: Rixse M. G. , Thorogood J. L.
Published: December 2007

A service company and operator worked together to build a system to assure technical integrity within the service company's field operating unit. They created systems and procedures to address how the service company was organized; how it performed design, how it executed the service, and how it managed the logistical issues associated with performing the service. The procedures were structured to facilitate the gathering and application of new knowledge.

The process was initially tackled from an ISO 9000 quality management standpoint, but the result lacked usefulness and was rejected. A more direct and universal approach was adopted that emphasized the safety-critical and cost-critical processes that are paramount requirements of an oilwell service operation.

Development of these systems required extensive thought to define the exact scope of the issues that needed to be addressed. The system had to be structured so that it would be actively utilized and not become a bureaucratic burden. Significant organizational culture changes were required to encourage personnel to learn and operate within the defined procedures. Using commonly available computer software, systems were implemented that provided access to the policies and procedures actively used by both the operator and the service company. The computer software furnished a simple framework to promote learning within the contractor's organization.
Directional Drilling and Earth Curvature
Authors: Williamson H. S. , Wilson H. F.
Published: December 2007

This paper provides a review of current practices for calculating directional drilling placement in the light of modern extended-reach applications. The review highlights the potential for gross errors in the application of geodetic reference information and errors inherent in the calculation method. Both types of error are quantified theoretically and illustrated with a real example. The authors borrow established land surveying calculation methods to develop a revised best practice for directional drilling. For the elimination of gross errors they prescribe increased awareness and a more disciplined approach to the handling of positional data.
Mechanical Strength of Reservoir Materials: Key Information for Sand Prediction
Authors: Zhang J. J. , Rai C. S. , Sondergeld C. H.
Published: December 2007

The mechanical strength of a reservoir formation is the most crucial information required for predicting sand production and recommending sand control completion. So far, the only reliable technique to obtain the formation strength quantitatively is to perform laboratory tests on core samples. The laboratory tests require substantial volumes of cores, which in most cases are not available. In this study, we present a new method to avoid this restriction. The significance of this approach is in its simplicity and efficiency in constructing a reliable mechanical failure envelope. The key results of this study, based on measurements on a variety of sandstones, are the following.

A single normalized failure envelope characterizes sandstone formations. This universal curve makes it possible to construct the failure envelope for a sandstone formation from the knowledge of critical pressure. There exists a correlation between the critical pressure and the compressional wave velocity (at equivalent depths of burial). The failure envelope for a sandstone formation can then be constructed simply from compressional wave velocities. These velocities are generally accessible from conventional logging data.
Interrelationship of Wettability, Initial Water Saturation, Aging Time, and Oil Recovery by Spontaneous Imbibition and Waterflooding
Authors: Zhou Xianmin , Morrow N. R. , Ma Shouxiang
Published: December 2007

Previous studies of crude oil/brine/rock (COBR) and related systems showed that wettability and its effect on oil recovery depend on numerous complex interactions. In the present work, the wettability of COBR systems prepared using Prudhoe Bay crude oil, a synthetic formation brine, and Berea Sandstone was varied by systematic change in initial water saturation and length of aging time at reservoir temperature (88°C). All displacement tests were run at ambient temperature. Various degrees of water wetness were achieved and quantified by a modified Amott wettability index to water, the relative pseudowork of imbibition, and a newly defined apparent advancing dynamic contact angle.

Pairs of spontaneous imbibition (oil recovery by spontaneous imbibition of water) and waterflood (oil recovery vs. pore volumes of water injected) curves were measured for each of the induced wetting states. Several trends were observed. Imbibition rate, and hence, water wetness, decreased with increase in aging time and with decrease in initial water saturation. Breakthrough recoveries and final oil recovery by waterflooding increased with decrease in water wetness. Correlations between water wetness and oil recovery by waterflooding and spontaneous imbibition are presented.
Experimental Study of Wettability Alteration to Preferential Gas-Wetting in Porous Media and Its Effects
Authors: Li Kewen , Firoozabadi Abbas
Published: December 2007

In a recent theoretical study, Li and Firoozabadi [Li, K. and Firoozabadi, A.: "Phenomenological Modeling of Critical-Condensate Saturation and Relative Permeabilities in GasCondensate Systems," paper SPE 56014 available from SPE, Richardson, Texas (2000)] showed that if the wettability of porous media can be altered from preferential liquid-wetting to preferential gas-wetting, then gas-well deliverability in gas-condensate reservoirs can be increased. In this article, we present the results that the wettability of porous media may indeed be altered from preferential liquid-wetting to preferential gas-wetting. In the petroleum literature, it is often assumed that the contact angle through liquid-phase θ is equal to 0° for gas-liquid systems in rocks. As this work will show, while θ is always small, it may not always be zero. In laboratory experiments, we altered the wettability of porous media to preferential gas-wetting by using two chemicals, FC754 and FC722. Results show that in the glass capillary tube θ can be altered from about 50 to 90° and from 0 to 60° by FC754 for water-air and normal decane-air systems, respectively. While untreated Berea saturated with air has a 60% imbibition of water, its imbibition of water after chemical treatment is almost zero and its imbibition of normal decane is substantially reduced. FC722 has a more pronounced effect on the wettability alteration to preferential gas-wetting. In a glass capillary tube θ is altered from 50 to 120° and from 0 to 60° for water-air and normal decane-air systems, respectively. Similarly, because of wettability alteration with FC722, there is no imbibition of either oil or water in both Berea and chalk samples with or without initial brine saturation. Entry capillary pressure measurements in Berea and chalk give a clear demonstration that the wettability of porous media can be permanently altered to preferential gas-wetting.
Steady-State Upscaling: From Lamina-Scale to Full-Field Model
Authors: Pickup Gillian , Ringrose P. S. , Sharif Ahmed
Published: December 2007

In recent years, the impact of small-scale permeability structure on hydrocarbon recovery has been demonstrated, and upscaling procedures, such as the geopseudo method, have been developed to scale-up from the lamina scale using the hierarchy of geological length scales. However, upscaling is very time consuming, so many engineers still input rock curves into large-scale simulations. In this study, we show how the process may be speeded up using steady-state methods for calculating the pseudofunctions.

Two examples are used to demonstrate the method. The first is a three-stage scale-up of a water flood in a fluvio-aeolian model. Capillary equilibrium was assumed for the first two stages, and viscous-dominated steady state for the third stage. Two different wettability cases were examined—water-wet and intermediate-wet. The effect of using the small-scale pseudo relative permeabilities depends on both the nature of the heterogeneities and on the wettability. In this study the recovery was reduced when small-scale pseudos were included, especially in the water-wet case.

The second case study involved gas injection into the oil leg of a tidal deltaic reservoir. Scale-up was performed in two stages: (a) from the lithofacies scale to the geological model, and (b) from the geological model to the full-field simulation model. The viscous-dominated steady-state method was used in both cases. The results showed that the effect of the fine-scale heterogeneities was of the same order as the effect of the coarse-scale heterogeneity, indicating that (even in a system where capillary pressure is negligible) the fine-scale structure can be important.
Approximate Model for Productivity of Nonconventional Wells in Heterogeneous Reservoirs
Authors: Wolfsteiner Christian , Durlofsky L. J. , Aziz Khalid
Published: December 2007

A semianalytical method is presented for the approximate modeling of the productivity of nonconventional wells in heterogeneous reservoirs. The approach is based on Green's functions and represents an extension of a previous model applicable for homogeneous systems. The new method, referred to as the s–k* approach, models permeability heterogeneity in terms of an effective skin s that varies along the well trajectory and a constant background permeability k*. The skin is computed through local, weighted integrations of the permeability in the near-well region and is then incorporated into the semianalytical solution method. The overall method, which can also model effects due to wellbore hydraulics, is quite efficient in comparison to detailed finite-difference calculations.

Results for the performance of nonconventional wells in threedimensional heterogeneous reservoirs are computed using the s-k* approach and compared to finite-difference calculations resolved on the geostatistical fine grid. The new method is shown to provide an accurate estimate of wellbore pressure and production rate, as a function of position along the wellbore, for various well configurations and heterogeneous permeability fields. The possible use of the overall approach in a simulation while drilling (SWD) tool, in which the well path and trajectory are "optimized" using real-time data, is also discussed.
Theoretical Model and Numerical Investigation of Near-Wellbore Effects in Hydraulic Fracturing
Authors: Romero Jean , Mack M. G. , Elbel J. L.
Published: December 2007

The high near-wellbore pressure drop, which has frequently been reported in fracture treatments, is indicative of ineffective communication between the wellbore and the fracture. Although numerous observations of such effects have been published, few attempts have been made to understand them. This article describes three possible mechanisms of near-wellbore effects [perforation phasing misalignment-induced rock pinching, perforation pressure drop, and fracture reorientation (deviation tortuosity)] and their implementation in a numerical fracture simulator. Typical signatures of all three effects in fracture treatment records are shown, and a method is proposed by which to distinguish them.

Perforation phasing misalignment has been identified as a cause of near-wellbore restriction. Because the fracture does not always initiate at the perforation, the fluid must communicate with the fracture through a narrow channel (microannulus) around the casing. Here we describe this pinching effect and show that it is related to the contact stress between the cement and the formation. Perforation pressure drop and deviation tortuosity, which have previously been proposed by other authors, have also been modeled. They have been incorporated into the simulator, together with the phasing misalignment effect, to allow investigation of the differences in response between the different mechanisms. Results of simulating the effects of erosion of near-well effects on treating pressure are also shown.

Comprehensive field cases studies exhibiting near-wellbore mechanics are presented. The relevant near-wellbore mechanism is first identified and the downhole pressure is then simulated, demonstrating the validity of the model.
New Approach for Enhancing Fracture Conductivity
Authors: Nguyen P. D. , Dewprashad B. T. , Weaver J. D.
Published: December 2007

A new liquid surface-modification system was developed for coating proppant, dramatically increasing its surface friction and allowing it to interact instantaneously with surrounding particulates. High surface friction between coated proppant grains allows them to withstand high flow rates, minimizing their flowback potential after fracture-stimulation treatments.

According to field results, when this surface-modification material was used as a flowback-control agent after conventional fracturing treatments, it permitted more aggressive flowback procedures. This treatment did not impair conductivity, and, in fact, increased proppant conductivity at closure stresses below 4,000 psi. Better vertical proppant distribution occurred in experiments that demonstrated how the surface modification significantly hindered proppant settling. Fines that already existed within the prop-pant (generated from the formation or derived from crushed proppant upon fracture closure) all adhered to the treated proppant, which inhibited them from migrating and blocking pore throats of the proppant pack. This unique coating technology further enhanced conductivity by improving fracturing-gel breaker action in certain fluids. This behavior results in faster, more effective well cleanup after stimulation.
Laboratory, Theoretical, and Field Studies of Emulsified Acid Treatments in High-Temperature Carbonate Formations
Authors: Navarrete R. C. , Holms B. A. , McConnell S. B. , Linton D. E.
Published: December 2007

Emulsified acids were traditionally used in acid fracturing, and more recently on matrix treatments of carbonate formations. The delayed nature of emulsified acids is useful in generating longer etched fractures or deeper wormholes. Emulsified acids also have higher viscosities than straight acid, which reduces fluid loss in acid fracturing applications and helps distribute acid more uniformly in formations with high-permeability contrast during matrix treatments. A new emulsified acid system is presented in this paper that is stable up to 350°F, highly retarded, and significantly more viscous than straight acid. Laboratory data comparing emulsified acid with straight acid are presented at temperatures ranging up to 350°F, including rheology and acid conductivity. Field case histories in the Smackover formation in Alabama over two years are presented. The field case histories show the improvements in production of oil and gas resulting from emulsified acid fracturing treatments in comparison with prior similar treatments done with straight acid.
Modeling Scale-Inhibitor Treatments in Horizontal Wells: Application to the Alba Field
Authors: Mackay E. J. , Matharu A. P. , Sorbie K. S. , Jordan M. M. , Richard Tomlins
Published: December 2007

Many horizontal wells produce both oil and brine for an extended period of time and, therefore, in many cases the problem of mineral scale deposition must be solved. Scale management in long horizontal wells faces several challenges, a major one being the correct placement of the scale inhibitor slug in the formation. Accurate placement is required to ensure that vulnerable well sectors are treated, without wasting chemical in the protection of zones which will not cut water during the lifetime of the squeeze treatment.

This paper presents results from a novel nearwellbore simulator (assist2), which is used to model scale inhibitor treatments in horizontal wells. A technique for modeling such treatments has been developed which gives an improved understanding of where the chemical will be placed under different injection strategies, and how the placement will impact the squeeze life. It also allows the engineer to assess the impact of varying such parameters as inhibitor slug volume and concentration, overflush volume, injection rate, etc. Different inhibitor chemicals can be compared for their performance under the given reservoir conditions.

This technique has been applied to model a squeeze treatment in a horizontal well where good production data are available. Connection oil and water flow rates, calculated by a full-field simulation model, have been matched by assist2. Various treatment designs were tested to assess the impact of the controllable parameters listed above. Findings enabled a treatment to be specified that was predicted to increase the squeeze lifetime without increasing the volume of chemical required. This modeled application strategy will also reduce the initial inhibitor concentration spike in the return curve. The performance of various chemicals under reservoir flow conditions was modeled, with a clear best choice emerging from these studies.

Based on the findings of this modeling work, recommendations were made for a squeeze treatment, which were implemented, and the resulting field data are presented.
Development of a Downhole Oil/Water Separation and Reinjection System for Offshore Application
Authors: Bowers B. E. , Brownlee R. F. , Schrenkel P. J.
Published: December 2007

Hydrocyclone-based systems for downhole separation of produced oil and water and subsequent disposal of the produced water by reinjection within the same wellbore have been successfully applied in a number of onshore wells. Benefits of these systems include reduced produced water lifting and disposal costs, as well as a significant reduction in liquid load on surface processing facilities.1 Reduction in surface equipment requirements is of primary interest in offshore applications, where significant reduction in the size and cost of surface separation facilities promises to extend field life and make marginal developments economically viable. Further development of downhole separation and reinjection systems is underway in order to provide a range of hardware systems suitable for a variety of offshore applications.
Mobility Ratio - Its Influence on Injection or Production Histories in Five-Spot Water Flood
Authors: Aronofsky J.S. , Ramey H.J.
Published: December 2007

Potentiometric model studies of the five-spot water flood to determine the influence of mobility ratio upon injection or production histories are described. The results, suggest a method for the correlation of data from field pilot tests for the estimation of an effective mobility ratio and its effect upon field water floods. The effect of the well spacing-to-well radius ratio upon production histories is presented. A method of accounting for this factor is suggested. The influence of injection (or production) rates and injection and production well pressures upon production histories is shown. The fivespot well pattern was investigated for water-to-oil mobility ratios of 0.1 to infinity.

Introduction

It has been well established that mobility ratio has an important effect upon flood patterns. It should be equally apparent that injection and production histories must also be influenced by mobility ratio. However, none of the articles referred to above mention the importance of being able to predict the effect of well pressures (or injection rates) during the entire time history of a waterflood operation. A complete description of production histories (the terms "injection" and "production" are synonymous for the steady-state model under consideration) would provide values for well pressures and interface positions at any time for a specified injection rate. Conversely, if the waterflood problem is specified in terms of a constant injection well pressure, then it would be desirable to know the injection rate and interface positions at any time.
Differential-Sticking Mechanisms and a Simple Wellsite Test for Monitoring and Optimizing Drilling Mud Properties
Authors: Reid P. I. , Meeten G. H. , Way P. W. , Clark Peter , Chambers B. D. , Gilmour Alan , Sanders M. W.
Published: December 2007

Differential sticking has a major impact on drilling efficiency and well costs. It is known to be influenced by drilling-fluid properties and other parameters, such as the characteristics of rock formations. Mechanisms of differential sticking were investigated using laboratory data and information in the literature. The knowledge gained was used to design a simple and robust device for measuring the sticking properties of drilling fluids, both in the laboratory, or at the well site.

This device comprises a half-area high-pressure, high-temperature (HPHT) fluid-loss cell, modified to allow a metal sphere to be placed in contact with a growing mud filter cake. The torque required to rotate the sphere free from the mud cake is determined using an electronic torque gauge. A plot of torque against the 3/4 power of time gives a linear fit to the data. The slope of this line is indicative of the sticking potential of the mud.

Laboratory and field data indicate that the test gives a good indication of mud condition and allows the user to investigate various options for reducing the sticking potential of the fluid. This information is useful both in the initial selection of mud type and in making technical and economic analyses of various mud treatment options. In addition to the laboratory evaluation described above, the sticking device has been used in several well-site tests with encouraging results. Some of these are described.
Flow Visualization Studies of Solution Gas Drive Process in Heavy Oil Reservoirs With a Glass Micromodel
Authors: Bora R. , Maini B. B. , Chakma A.
Published: December 2007

A series of flow visualization experiments was carried out to examine the pore scale behavior of the solution gas drive process in heavy oil reservoirs. The main objective was to testify several speculative theories that had been put forward to explain the anomalous production behavior of heavy oil reservoirs producing under the solution gas drive process. Contrary to previous postulations, the asphaltene constituents did not appear to play a significant role in the nucleation and stabilization of the gas bubbles that evolved during the solution gas drive process. Experimental evidence also suggests that the production of heavy oil is not accompanied by a large population of microbubbles. These observations suggest that the production enhancement in the solution gas process in heavy oil reservoirs may be related to other mechanisms such as viscous coupling effects, sand production, wormhole effects, etc.
Production Forecasting of an Unstable Compacting Chalk Field Using Uncertainty Analysis
Authors: Hegdal T. , Dixon R. T. , Martinsen R.
Published: December 2007

Past years' forecasting performance has demonstrated that single "most likely" (deterministic) prediction of future production, without quantifying the associated uncertainties, is inadequate for management and planning purposes. Based on this an effort was initiated to improve the forecasting methodology and procedures with special emphasis on quantifying the uncertainty in short-term production forecasting (STPF).

The Valhall field, offshore Norway, presented special problems for production forecasting because many unusual events affect production, even for STPF. The soft compacting reservoir chalk causes well collapses and chalk influxes and makes drilling difficult. Modeling of reservoir fracturing and therefore well performance is also uncertain.

A probabilistic forecasting approach was adopted using a customized spreadsheet and commercially available statistical analysis add ins which allowed deterministic forecasting, partially probabilistic analysis, or fully integrated uncertainty analysis. Uncertainties were characterized by distributions based on historical data where possible.

Communication and integration of knowledge were also key success factors since the process required input from several departments and many individuals to ensure that the "company knowledge" was fully reflected. A "common language" to communicate uncertainty and an auditable process to ensure buy in and consistency were also critical.
A Study of the Chemical Interactions Between Brine Solutions and Dolomite
Authors: Zou B. , McCool C. S. , Green D. W. , Willhite G. P.
Published: December 2007

Application of gelled polymer treatments to change the flow characteristics of a reservoir is a viable improved oil recovery technique. Many gel systems are affected by the solution pH in that gel time is pH dependent. The treatment of carbonate reservoir rock is of particular concern because (1) fluid-rock interaction can alter the pH of the injected solution from the design value and (2) dissolution of carbonate can increase the divalent ion concentration, which can also affect gelation behavior.

In this study, the interaction between injected potassium chloride brine and dolomite was investigated through displacement experiments in dolomite cores and mathematical modeling based on equilibrium thermodynamics. Parameters varied were pH of the injected solution, flow rate, and the common ion effect through variation of the calcium and magnesium ion concentrations in the injected solution. Core effluent values of pH and concentrations were measured. Experiments at different flow rates established conditions in which equilibrium was achieved in the core. Equilibrium values of pH were almost constant at a value of 10 when the injected pH was varied between 4 and 10. Results indicate that equilibrium conditions exist for most field conditions.

A geochemical model was used to predict equilibrium pH and concentrations, as well as the amount of dolomite dissolved. The model accurately predicted effluent pH of experimental displacement data for the conditions wherein equilibrium was achieved. All model parameters were obtained from literature equilibrium data and were not dependent on curve fitting of the experimental data.
Understanding Wormholing Mechanisms Can Improve Acid Treatments in Carbonate Formations
Authors: Buijse M. A.
Published: December 2007

In this paper, acid wormholing in carbonate formations is studied. The wormhole growth rate and the geometry of the final worm-hole pattern depend on the combined effect of acid spending and fluid flow. Acid spending is studied by modeling the wormhole as a cylindrical pore and numerically solving the convection-diffusion equations. A finite acid-rock reaction rate is assumed, allowing calculation and study of spending profiles in both the diffusion-controlled and the reaction-controlled regime. Flow properties such as fluid loss from wormhole to formation and fluid distribution in a multiple wormhole geometry are studied through numerical simulations. It is shown how wormhole growth properties are affected by the length and distance of neighboring worm-holes. The effect of injection rate and diffusion is studied with a simple model. This model explains several experimentally observed phenomena, such as the existence of an optimum injection rate and a reduced wormhole efficiency at higher rates.
Multipurpose Wells: Downhole Oil/Water Separation in the Future
Authors: Stuebinger L. A. , Elphingstone G. M.
Published: December 2007

Promising new technologies are being advanced to reshape development strategies in your fields. It is not always necessary to dedicate wells to production or injection; now, both functions can be performed within one multipurpose wellbore. Technologies exist to reduce water-handling volumes at the surface by keeping the water downhole.

The discovery of downhole oil, water, and gas gravity segregation in the wellbore and the ability to keep fluids separated makes it possible to generate revenue from a wellbore at the same time that it is injecting or disposing water. This paper will discuss:

design and testing at the Rocky Mountain Oilfield Testing Center of the first downhole oil-water separation artificial lift system to utilize downhole gravity segregation; evolving modeling procedures; superior environmental performance; impediments to deploying radically new technologies; and a vision of the future.
Field Results of Separation-Vessel and Multiphase-Flowline Debottlenecking Using an In-line Gas/Liquid Auger Separator
Authors: Weingarten J. S.
Published: December 2007

Field results of Auger separator installations are presented which demonstrate the following new applications of in-line gas/liquid partial separation: (1) increasing separation vessel capacity (or reducing required vessel size for a given flow rate) and (2) reducing pressure drop in multiphase lines that transport produced hydrocarbons. The Auger separator is a device which partially separates liquid and gas, has no moving parts, and requires no power or level controls. The diameter of the separator is typically a few inches, generally about the same diameter as the line, and is installed as a spool piece in the line. In one application, a field test was conducted where the Auger separator was placed just upstream of a conventional test separator. By removing a portion of the gas upstream, the liquid capacity of the vessel was approximately doubled. In a different application, Auger separators were installed to remove gas from multiphase-flowlines and provide raw gas lift on the drillsite. By doing this, the amount of gas in the production line was reduced, decreasing the backpressure and increasing the capacity for produced fluids. The operating conditions before and after the installations, equipment descriptions and photographs, piping layouts, and operational considerations are included. The design of the Auger separators and performance comparisons to predictions from design equations are also discussed.
Efficient Finite-Difference Model for Flow in a Reservoir With Multiple Length-Scale Fractures
Authors: Lee S. H. , Jensen C. L. , Lough M. F.
Published: December 2007

In this paper we describe a hierarchical approach for modeling fluid flow in a naturally fractured reservoir with multiple length-scale fractures. Based on fracture length relative to the finite-difference grid size, fractures are classified as short disconnected fractures, medium-length fractures, and long fractures. Effective grid-block permeabilities, associated with the short-and medium-length fractures, are used as input to a finite-difference simulator. We also present a separate transport equation for flow through long fractures to capture effects of large-scale high permeability pathways. Simulation results from the new hierarchical approach are compared with those from the conventional dual porosity/permeability model.
Helical Buckling of Pipe With Connectors in Vertical Wells
Authors: Mitchell R. F.
Published: December 2007

The effect of connectors on pipe buckling is acknowledged, but has received little attention. Lubinski analyzed the effect of connectors on pipe in tension in a curved borehole, while Paslay and Cernocky extended this analysis to pipe in compression. These papers indicate that bending stresses are greater due to connector standoff. However, these papers do not consider a buckled pipe.

This paper presents an analytic solution of the beam-column equations in three dimensions for a helically buckled pipe with connectors in a vertical well. For low axial compression, the solution approximates helically buckled pipe without connectors, however, at higher axial forces, the effects of connectors on contact forces and bending stress becomes significant. Sag between connectors is calculated so that pipe body contact between connectors can be determined.

Applications include the analysis of bottomhole assemblies, drillpipe, casing, and tubing. The solutions are simple formulas that are suitable for hand calculations.
Geomechanical Modeling of Reservoir Compaction, Surface Subsidence, and Casing Damage at the Belridge Diatomite Field
Authors: Fredrich J. T. , Arguello J. G. , Deitrick G. L. , de Rouffignac E. P.
Published: December 2007

Geologic, and historical well failure, production, and injection data were analyzed to guide development of three-dimensional geomechanical models of the Belridge diatomite field, California. The central premise of the numerical simulations is that spatial gradients in pore pressure induced by production and injection in a low permeability reservoir may perturb the local stresses and cause subsurface deformation sufficient to result in well failure. Time-dependent reservoir pressure fields that were calculated from three-dimensional black oil reservoir simulations were coupled unidirectionally to three-dimensional nonlinear finite element geomechanical simulations. The reservoir models included nearly 100,000 gridblocks (100 to 200 wells), and covered nearly 20 years of production and injection. The geomechanical models were meshed from structure maps and contained more than 300,000 nodal points. Shear strain localization along weak bedding planes that causes casing doglegs in the field was accommodated in the model by contact surfaces located immediately above the reservoir and at two locations in the overburden. The geomechanical simulations are validated by comparison of the predicted surface subsidence with field measurements, and by comparison of predicted deformation with observed casing damage. Additionally, simulations performed for two independently developed areas at South Belridge, Secs. 33 and 29, corroborate their different well failure histories. The simulations suggest the three types of casing damage observed, and show that, although water injection has mitigated surface subsidence, it can, under some circumstances, increase the lateral gradients in effective stress that in turn can accelerate subsurface horizontal motions. Geomechanical simulation is an important reservoir management tool that can be used to identify optimal operating policies to mitigate casing damage for existing field developments, and applied to incorporate the effect of well failure potential in economic analyses of alternative infilling and development options.
Novel Application of Emulsified Acids to Matrix Stimulation of Heterogeneous Formations
Authors: Buijse M. A. , van Domelen M. S.
Published: December 2007

Historically, emulsified acids have primarily been used in fracture acidizing. By combining information from theoretical studies, experimental studies, and field testing, a better understanding has recently been gained of the application of emulsified acids in matrix acidizing. This paper discusses the use of emulsified acid as a stimulation fluid for matrix treatments in heterogeneous carbonate formations.

Emulsified acid is diffusion retarded which makes it an effective wormholing fluid at low injection rates that occur, for example, in low permeabiliy or damaged formations. At these low rates, plain HCl acid will mostly spend on the formation face and is unable to create wormholes that penetrate deep into the formation.

In this paper, results of flow tests are presented that compare the efficiency of emulsified acid with that of plain HCl acid. Several emulsified acid systems were tested. The effects of the injection rate, viscosity, and acid/oil volume ratio were analyzed on core samples. Rheological properties and temperature stability (up to 250°F) of the emulsion systems were analyzed by means of Fann-50 tests.

Acid-in-oil emulsions are effective stimulation fluids in large intervals where streaks of high permeability can act as thief zones. This is shown by means of example calculations of the fluid flow and distribution in a well.