bluuebunny/crossref_metadata_2025 huggingface dataset:
A New Streamline Method for Evaluating Uncertainty in Small-Scale, Two-Phase Flow Properties
Authors: Hastings J. J. , Muggeridge A. H. , Blunt M. J.
Published: December 2007

This paper presents a new, semianalytical streamline method that allows rapid quantification of the impact of small-scale heterogeneities in permeability and relative permeability on reservoir production and water cut. This is achieved using a new method for upscaling total mobility in 1D, combined with an existing method for fractional flow.1 The properties along each streamline are upscaled analytically to provide effective permeability, porosity, relative permeability, and geometry for that streamline.

The estimation of the oil recovery distribution, resulting from uncertainty about the small-scale heterogeneity, is further sped up by making a separation of scales assumption. The oil recovery distribution can then be calculated from the streamline simulator using only a single pressure solve. A stochastic model of a cross section through a synthetic fluvial reservoir is used to demonstrate the validity of this assumption.
The Impact of Upscaling Errors on Conditioning a Stochastic Channel to Pressure Data
Authors: Zhang Fengjun , Reynolds A. C. , Oliver D. S.
Published: December 2007

This work discusses an automatic history-matching procedure to efficiently condition the location and geometry of a stochastic channel to well-test pressure data. Our emphasis is on computational difficulties that are related to the nonlinearity of the objective function, or arise from the definition of effective permeability on a reservoir simulation gridblock that is intersected by one or more channel boundaries. We show that upscaling gridblock permeabilities for gridblocks intersected by channel boundaries introduces spurious local minima in the objective function that must be optimized to obtain a realization of the model.

We show that an automatic history-matching procedure can be used to define upscaled permeabilities. When the permeability contrasts across facies boundaries are extreme, however, the resulting properties may be influenced by the difference in local truncation errors between the fine- and coarse-grid systems. Moreover, the upscaled permeabilities obtained by history matching depend on the flow regimes reflected in the pressure data history matched.

The problems we observed are not specific to channels but will occur whenever boundaries of facies with large contrasts are estimated by history matching. One important objective of this work is to provide computational insight for the general problem of conditioning a reservoir facies model to production data by automatic history matching.
Acid Stimulation Studies in Simulated Radial Flow Conditions: Laboratory Results Compared With Field Data
Authors: Kotlar Hans Kr. , Hove Arvid O.
Published: December 2007

Most laboratory tests for qualifying acid-stimulation treatments are performed in traditional core-flow experiments. A single core is used with all treatment fluids flowing through the core in laminar pattern.

With this kind of experimentation, the contact time to the matrix and the spending acids' residence time will not match with actual field conditions. Thus, it will be difficult to reproduce possible secondary and tertiary reactions. Such reactions might prove to be very important, especially in "dirty" sand with a high clay content.

A survey done in the industry reveals that a third of all acid-stimulation jobs fail for various reasons, such as incorrect acid formulations, pumping schedule procedures, improper placement, and specific field-related problems with crossflow, etc.

This paper reports on the first experiments in acid-stimulation treatments with a multicore setup that simulates radial flow conditions. Furthermore, this is done in combination with two-phase flow.

These experiments use actual pumping and treatment schedules from the Gullfaks field. The results are compared with the actual field data.

The spent acid flowback, which represents the total acid injection volume, is analyzed for dissolved elements, and the treated cores are inspected by environmental scanning electron microscope (ESEM).

Tangible evidence indicates that secondary and tertiary reactions can be detected by this method.
New Low-Solids Oil-Based Mud Demonstrates Improved Returns as a Perforating Kill Pill
Authors: Jiang Ping , Taugbøl Knut , Mathisen Anne-Mette , Alterås Eva , Mo Christine
Published: December 2007

This paper describes the development of a low-solids oil-based fluid and its successful application as a kill pill in long, perforated horizontal wells in the Norwegian North Sea. The authors detail the investigative process that resulted in the development of the heavy, brine-based, internal-phase fluid system.

Simulated perforation formation-damage tests with and without zinc perforating debris were conducted on conventional brine-and oil-based fluid systems. The tests showed that the chemical reaction of the brine-based system to zinc debris significantly increased fluid loss. With the conventional oil-based mud, return flow efficiencies dropped by 10 to 15% when the zinc debris was added.

The newly developed low-solids, oil-based kill-pill system was engineered with a high content of heavy brine for fluid density and minimal solids content. The only solids in the system are calcium carbonate, which is used for bridging, and minimal amounts of clay and lime for rheology control and alkalinity, respectively. In perforation tests, it exhibited more than 80% return flow efficiency.
A Joint Industry Project To Assess Circulating Temperatures in Deepwater Wells
Authors: Ward M. , Granberry V. , Campos G. , Rausis M. , Sledz M. , Weber L. , Guillot D. , Naziri I. , Romero J.
Published: December 2007

Drilling oil wells offshore in water depths exceeding 1000 m is not uncommon in many parts of the world. These conditions present a number of challenges for successfully drilling and completing these wells. A major challenge is predicting the temperature of various fluids, such as drilling muds and cements, when they are circulated or placed in the well and during static periods. What sounds like an easy task for the majority of land or offshore wells with shallow water depths turns out to be much more difficult for deepwater wells. This is particularly caused by inverse temperature gradients across the sea and convective thermal exchanges between the sea and the fluids in the riser and/or drillpipe.

To better understand the phenomena involved, a series of temperature measurements was made as part of a joint industry project (JIP). The primary objective of these measurements was specifically to monitor the cooling effect of the sea by measuring the fluid temperature at the mudline depth. All temperature data were measured by a sensor deployed inside the bottomhole assembly (BHA) while circulating or drilling. Data were collected in the Gulf of Mexico, Brazil, Indonesia, and west Africa in an average water depth of 1200 m.

A summary of the temperature measurements is presented, and comparison is also made with the predictions of a numerical simulator. Detailed interpretation of the data gathered pinpoints the importance of correctly accounting for the exact temperature profile in the sea as well as the velocity of sea currents vs. depth.
The Future of Aerated Fluids in the Drilling Industry
Authors: Huddleston Billy Pete , Strange William D.
Published: December 2007

The present techniques of air or gas drilling and their advantages and disadvantages are discussed. The relative merits of both air and mud drilling provide the basis for the advent of aerated fluids. For the purpose of this discussion, aerated fluids are divided into two phases:physical composition andcirculation techniques.

From the previous comparison, conclusions are drawn with respect to the future of aerated fluids.

Introduction

The advent of aerated fluids was a result of an attempt to avoid the limitations and yet maintain the advantages of both conventional drilling muds and air or gas when used as a drilling medium. A brief philosophical review of the petroleum industry and a summation of air and gas drilling characteristics provide the foundation for this discussion of the development and the characteristics of aerated drilling fluids.

Many technological advancements into industry can often be attributed to either or both of two major demands:a physical demand for new processes in order to accomplish heretofore technically unfeasible tasks, orthe economic demand for an improvement of present techniques that were formerly considered prohibitive from a sound investment viewpoint.

The advent of aerated drilling fluids may be attributed to both demands.

Since drilling and completion annually of over 45,000 oil and gas wells provides a total operational outlay exceeding 30 per cent of the entire producing companies' expenditures, a small technological, and eventually in economic advancement, can be of paramount importance.

It appears that the most promising fields of improvement in drilling operations lie within three problems:the proper completion procedures for productive formations which have been damaged by the present drilling techniques,the reduction of lost circulation costs, andthe reduction of the over-all operational drilling costs.
Steamflooding Wabasca Tar Sand Through the Bottomwater Zone—Scaled Model Tests
Authors: Huygen Hans H. A. , Lowry W. E.
Published: December 2007

Steamflooding a tar sand with a communicating bottomwater zone was investigated in a three-dimensional, scaled, laboratory model. Scaling is discussed and equipment and procedures are described. We studied the process mechanisms and the influence of steam rate and initial oil saturation, and compared performance of single and multiple patterns.

The bottom water was found to counteract gravity segregation of the steam. If the steam rate is high enough, no gravity override occurs, and much of the formation is swept layer by layer, resulting in high recovery of oil. But oil/steam ratios are rather low, particularly at low initial oil saturation and in the single pattern pilot where oil bypasses the production wells.
Optimizing Pipeline Operations (includes associated papers 9974 and 10358 )
Authors: Gopal Vijender N.
Published: December 2007

This work shows that dynamic and integer programming techniques can helpmaximize cost savings by minimizing fuel usage during transportation ofoil and gas by pipelines. This is done by properly selecting thepump/compressor combination at the stations. The paper illustrates these techniques by solving a sample problem.

Introduction

A proper selection of a combination of pumps andcompressors, based on their individual fuel rates, isnecessary to maximize cost savings by using aminimum of fuel for transporting oil and gas bypipelines. The following shows how integerprogramming (IP) and dynamic programming (DP) techniques can be used effectively in such adecision-making process.Oil and gas companies spend millions of dollarsevery year in fuel costs for operating the engines.With the cost of oil and gas skyrocketing, it hasbecome almost imperative for pipeline companies tooptimize fuel usage at the stations. This involveskeeping a constant tab on each pump's or compressor'sefficiency and the associated fuel rates forvarious options of loading.This work assumes that the engines are loaded100% (the point where they are most efficient) - i.e., at their rated horsepower. For loadings other than100%, the techniques described still can be appliedbut will require some fine tuning on the part of theengineer to come up with a global optimum.The objective of this work is to make the oil andgas industry aware of the potential area where dollarsavings can be realized. Techniques like thosepresented in this paper can be useful in minimizingfuel costs.Henceforth, "pump" will mean a pump or acompressor. Any set of consistent units can be usedfor volume, pressure, and cost.

Problem

With the pipeline systems running below capacity, there is more pumping capability at the stations thanactually is needed. The objective is to bring on-line acombination of only those pumps which will pumpthe desired volume for minimum fuel cost. Theproblem can be stated in two parts.

Part 1 - Optimum Pump Combination

Minimize subject to the following constraints

Part 2 - Optimum Discharge Pressure

The optimum discharge pressure at any given stationcan lie anywhere between the upper and loweroperational limits.

JPT

P. 2063＾
Reservoir Description for a Surfactant/ Polymer Pilot in a Fractured, Oil-Wet Reservoir - North Burbank Unit Tract 97
Authors: Trantham J.C. , Threlkeld C.B. , Patterson H.L.
Published: December 2007

Synthesis of information from cores, logs, waterflood experience, transient pressure tests, geologic studies, log-inject-log measurements, and tracers was used to provide a coordinated reservoir description for designing and controlling a surfactant/polymer flood in a fractured, oil-wet reservoir under active waterflood.

Introduction

The North Burbank Unit Tract 97 surfactant/polymer pilot in Osage County, OK, is a cooperative project operated by Phillips Petroleum Co. for 17 working-interest owners, with support from the U.S. DOE. Before the start of continuous injection and production in the pilot pattern in Dec. 1975, a comprehensive reservoir study was conducted, including coring, logging, transient pressure tests, oil saturation measurements, prior waterflood history, and a geologic study. These were supplemented, during preflush injection, by freshwater production behavior and radioactive tracer investigations.This paper reports the results of these studies and their synthesis into a working reservoir description, which has provided the basis for planning and operating the pilot during the past 42 months. Discussion of the pilot performance is presented elsewhere.

General Characteristics of the North Burbank Reservoir

The North Burbank reservoir is a large sand body deposited near the shore of the Cherokee Sea of Pennsylvanian age. Though originally thought to be a series of overlapping offshore bars, recent geologic study shows it to be of fluvial origin. The sand averages 42 ft (12.8 m) in thickness, with a porosity of 16.8% and permeability 50 md. The formation is rather heterogeneous, both vertically and areally. Additional heterogeneity is imparted by a strongly directional east-west jointing, or fracturing, which results in a preferential east-west movement of injected fluids. Another important feature is that the sand is strongly oil-wet.

Tract 97

Waterflooding History

The pilot reservoir in Tract 97 (Fig. 1) was part of the 1954 phase of waterflood development. Because of the preferential east-west flow, the 20-acre (8.09-ha) pattern was developed as a staggered line drive with like wells in east-west lines. Water breakthrough and oil production response occurred nearly simultaneously at each of the Tract 97 producers, requiring about 8 months on the average. Fig. 2 shows the performance of Well 97-06, a typical response. Careful investigation of well behavior at various points in time from start of injection to peak oil production gave inconclusive results.

JPT

P. 1647＾
Sequestering Agents for Prevention of Scale Deposition in Oil Wells
Authors: Earlougher R.C. , Love W.W.
Published: December 2007

Precipitation of insoluble mineral deposits, in and near the wellbore and on down-hole well equipment, lowers production rates considerably in many oil fields. Scale deposits have been prevented in industrial equipment by conditioning the water with phosphate sequestering agents. Such agents inhibit crystal growth so that, when the ions combine to form insoluble compounds such as calcium carbonate, calcium sulfate, and barium sulfate, these minerals remain in colloidal suspension.

A 12-to–40 mesh, granular phosphate has been used successfully to prevent such deposition in oil wells. The phosphate granules are mixed with the sand injected into the producing formation during fracturing treatments. Tests show that the phosphate is slowly dissolved by produced well fluids, preventing scale deposition within the formation and on down-hole well equipment. More than 30 wells have been treated by this special phosphate fracturing method, and production data indicate that the problem of formation plugging by mineral deposition is being effectively overcome.

Introduction

A frequent oilfield problem is the well which declines sharply after being completed and tested for a good initial production rate. Often there is no apparent reason for the rapid decline, and the reservoir is known to hold large amounts of oil. In many of these cases, deposition of calcium carbonate, calcium sulfate, or barium sulfate may be curtailing production.

Mineral deposition occurs in the wellbore, in formation flow channels adjacent to the wellbore, and on down-hole well equipment such as pumps, rods, and screens. Such deposition may be caused by changes in reservoir equilibrium near the wellbore, or by the mixing of incompatible brines from different formations in openhole completions. These difficulties occur both in primary and secondary production wells.

Such deposits can sometimes be dissolved or disintegrated by acidizing, depending upon the amounts of carbonate they contain. If, however, the deposit consists principally of sulfates, it is usually necessary to fracture the well to overcome this obstruction.

A summary was made recently of the results of fracturing treatments on 187 waterflood production wells. This summary covers three years, and includes some treatments completed as recently as a few months ago. In virtually every case the remedial fracturing treatments were necessitated by mineral deposition in the well that plugged off the flow channels and reduced production.
Gamma Ray Spectral Evaluation Techniques Identify Fractured Shale Reservoirs and Source-Rock Characteristics
Authors: Fertl Walter H. , Rieke H.H.
Published: December 2007

Gamma ray spectral logging devices, in addition to total gamma ray counts, record the individual contributions of potassium-40 isotope, uranium series nuclide bismuth-214, and thorium series nuclide thallium-208. Application of these data to identify fractured shale reservoirs and source-rock characteristics of argillaceous sediments is discussed.

Introduction

Highly radioactive, black, organic-rich, and gaseous shales are encountered in several U.S. geologic provinces. Such organic-rich shales are not only potential source rocks but frequently owe their localized but significant production potential to natural fracture systems in an otherwise impermeable rock. These natural fracture systems normally are concentrated in the interbedded brittle, calcareous, cherty, or silty zones.Conventional logging and interpretive techniques are not adequate to evaluate satisfactorily the complex and frequently fractured shale reservoirs. Novel applications of gamma ray spectral logging data for characterizing these shale formations as to their reservoir properties and source-rock potential (SRP) are discussed here.Calcareous and silty zones, both characterized by low values of potassium and thorium but excessively high values of uranium, are located easily with natural gamma ray spectral information obtained from highly sensitive scintillation spectrometer logging tools. These interpretive concepts already have assisted in many successful gas- and oilwell completion and recompletion attempts in the more permeable and/or fractured intervals of such shale formations.Such logging information also allows a continuous monitoring of the SRP of shales in open and cased boreholes. Hence, both vertical and lateral SRP variations can be studied using appropriate mapping techniques. Gamma ray spectral data also assist in detailed stratigraphic correlations, because in addition to total gamma ray counts, individual gamma rays emitted by potassium-40 (K(40)), the uranium series nuclide bismuth-214 (Bi(214)), and the thorium series nuclide thallium-208 (TI(208)) are measured.K(40) emits gamma rays at 1.46 MeV, Bi(214) emanates gamma rays at 1.764 MeV, and TI(208) emanates gamma rays at 2.614 MeV. These nuclides are of particular interest to the oil industry because all are found, in various amounts, in subsurface formations as constituents of potential reservoir rocks. Based on an extensive literature search and on recent field observations, a data compilation has been published to document potassium, uranium, and thorium distributions in various rock types.This discussion focuses on the use of gamma ray spectral logging to interpret the reservoir pore structure present in shales.

JPT

P. 2053＾
Lateral Buckling of Pipe With Connectors in Horizontal Wells
Authors: Mitchell R. F.
Published: December 2007

The effect of connectors on pipe buckling has only recently received attention. For nonbuckled pipe, Lubinski analyzed the effect of connectors on pipe in tension in a curved borehole, and Paslay and Cernocky extended this analysis to pipe in compression. The first analysis of buckled pipe with connectors was done by Mitchell, who developed a 3D analysis of helical buckling. These papers indicate that bending stresses are greater because of connector standoff.

Laterally buckled pipe with connectors is analyzed for the first time in this paper. It presents an analytic solution of the beam-column equations in 3D in a horizontal wellbore with pipe weight. Pipe deflections, contact loads, and bending stresses are determined with explicit formulas. Sag between connectors is calculated so that pipe body contact with the wellbore 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.
Streamline-Based Method With Full-Physics Forward Simulation for History-Matching Performance Data of a North Sea Field
Authors: Agarwal Bijan , Blunt Martin J.
Published: December 2007

We present a method for history-matching production data using a streamline simulation that captures all the pertinent physics, including compressible three-phase flow with gravity. We use an approach based on the assumption of 1D flow along streamlines to find the sensitivity of water flow rate at production wells to changes in permeability. Although the computation of the sensitivities is approximate, we show, using data from a North Sea field, that the method can provide a reasonable history match and good predictions of future performance for problems with significant effects caused by compressibility and gravity.
Aspects of Hydrodynamic Loading in Design of Production Risers
Authors: Loken A.E. , Torset O.P. , Mathiassen S. , Arnesen T.
Published: December 2007

This paper describes an experimental program undertaken to understand better the hydrodynamic loading of multitube production risers. Test results are described, and a generalization is given for engineering applications. Sample design calculations are performed.

Introduction

In recent years, much attention has been paid to analyzing the response of drilling risers. Most effort has been focused on the development of structural and analytical techniques to predict the stresses in riser systems. The analytical tools are, to a certain extent, calibrated by full-scale measurement. API published a comparison] of nine different, independent calculations of riser response that were in close agreement.Normally, drilling risers have a simple cross section for which the hydrodynamic forces are fairly well known. Extensive studies during many years have established insight into the flow patterns around a single smooth cylinder in constant flow and the corresponding forces. For multitube production risers the hydrodynamic load pattern is far more complex.Research is continuously improving the knowledge of flow-induced forces, particularly the influence of these parameters: high Reynolds number at prototype condition, effect of roughness, proximity effect of closely spaced cylinders, current/wave interaction, and effects of irregular seas.The state of the art regarding hydrodynamic loading on single cylinders in constant and oscillatory flow as a function of varying roughness has been published by Miller and Sarpkaya. Correspondingly, multiple cylinders have been considered by Zdravkovich, Bushnell, and Sarpkaya.To understand better the hydrodynamic loading of multitube production risers, Kongsberg Vapenfabrikk initiated an experimental program early in 1977. This program consisted initially of five riser configurations and one single cylinder to be tested in constant and oscillatory flow. A comparison with published data was made to check the experimental procedure and results against the state of the art. The experimental program later was extended by 18 additional geometries, sponsored by 10 oil companies as a joint industry program.The tests in constant flow were carried out at the Danish Hydraulic Inst. (DHI), while the oscillatory flow tests were performed at the Hydraulic Research Station (HRS). Det norske Veritas was consultant for the project and supervised the experimental work and the data interpretation procedures.This paper describes the experimental program, the test results, and a possible generalization for arriving at a simple engineering application of results.The discussion of sensitivity of important parameters in determining design loads is based on an actual design case. Design calculations performed by Kongsberg Vapenfabrikk for a production riser in deep water are presented.

JPT

P. 881＾
Canada's Pembina Field
Authors: Justen John J.
Published: December 2007

The Pembina field is the largest in Canada and one of the largest in the North American continent. Much of the published data concerning this reservoir is compared and summarized such that the geological, rock, and crude characteristics are indicated. The reservoir was initially undersaturated.

The production history is reviewed. The natural recovery mechanism is indicated to be solution gas drive. Engineering studies indicate that the ultimate recovery for various areas will be more than doubled if pressure is maintained by water flooding. With pressure maintenance the field will be in the billion barrel. reserve class. Pressure maintenance operations have commenced in various areas, using the existing wells in a 160-acre, five-spot pattern. A response to water injection has been reported in one area. By the end of 1957 about 50,000 acres will be under flood with water obtained from the North Saskatchewan River.

Introduction

In mid–1953 the successful completion of the wildcat, Pembina No. 1, recorded the discovery of the Pembina field. Today, four years later, one-fifth of Canada's daily crude oil production, and one-eighth of Canada's daily crude oil requirements are produced by the Pembina field.

The Pembina field is located in the Province of Alberta in Western Canada, 70 miles west-southwest from the city of Edmonton as indicated in Fig. 1. Its area, as defined by Alberta's Oil and Gas Conservation Board, is in the order of 400,000 acres. There are currently more than 1,750 producing wells representing 175,000 developed acres. The current production rate is over 110,000 BOPD. There are 43 operators in the field ranging from Mobil Oil of Canada, Ltd. which recently completed its 500th well, to Canadian Delhi, Ltd. with one well.

In area and production, this field is the largest in Canada. It is also one of the largest in the North American continent.

Geology

The reservoir is a stratigraphic trap resulting from the up-dip "shale-out" of the Cardium sand. The strike is slightly north of northwest and regional dip is to the southwest at a rate varying from 30 ft/mile in the northeast extremity of the field to 60 ft/mile in the southwest portion of the field. The Cardium sand is encountered at depths varying from 4,600 to 5,800 ft across the field. A contour map on top of the porosity is presented in Fig. 2.
Determination of Hydrocarbon Properties by Optical Analysis During Wireline Fluid Sampling
Authors: Dusen Alexandra Van , Williams Stephen , Fadnes Finn Hallstein , Irvine-Fortescue Jamie
Published: December 2007

Recent innovations in wireline fluid sampling have allowed the expedient recovery of high-quality oil samples. The use of the Optical Fluid Analyzer† (OFA), a part of the Modular Formation Dynamics Tester† (MDT), to predict sample fluid type and quality has now become an essential part of the sampling process. The ability to use the optical data from the OFA in a more quantitative manner has been under development for several years. This paper demonstrates that the analysis of the optical spectra measured downhole can be used to give a quantitative indication of some hydrocarbon properties before or during sampling. Clearly, there are many potential benefits to be gained from using these optical spectra while sampling to assist in reservoir characterization and determination of oil type.

Optical data gathered while taking oil samples in 21 wells (drilled with water-based mud) offshore Norway were correlated with the pressure/volume/temperature (PVT) properties of those samples. The samples were selected to ensure a wide range of oil types to establish correlations between the fluid and optical properties. Correlations have been found between the optical response and some fluid properties, as determined from PVT laboratory measurements of the samples. Oil density, saturation pressure (pb), oil compressibility (co), formation volume factor (Bo), and gas/oil ratio (GOR) gave good correlations. Weaker correlations were found with other properties. The GOR and the optical responses could become measured variables with the possible future addition of a GOR measurement sensor to the MDT. Improved correlations are demonstrated when this feature is simulated. The results of this study show that the optical data measured during wireline fluid sampling can help determine key in-situ hydrocarbon properties.
Effect of Tool Joints on Contact Force and Axial-Force Transfer in Horizontal Wellbores
Authors: Duman O. B. , Miska S. , Kuru E.
Published: December 2007

An experimental study has been conducted to investigate the effect of tool joints on the buckling/post-buckling behavior of drillpipes constrained in straight horizontal wellbores. Buckling/post-buckling behavior of drillpipes has traditionally been investigated with continuous pipes. To our knowledge, this is the first time the effect of tool joints is included in such a study.

The U. of Tulsa Drilling Research Projects experimental buckling facility has been used to carry out the desired experiments.

Axial loads at both ends of the pipe and contact forces at the tool joints were measured. Changes in the drillpipe configuration were also investigated visually as the axial load increases.

Some of the new findings of this study can be summarized as follows.

Sequential occurrence of buckling/post-buckling configuration of jointed pipe is similar to that of continuous pipes, reported previously by various investigators. In other words, in both cases, the pipes buckle first laterally and then helically as the axial compressive load increased. The presence of tool joints does not affect the critical lateral (sinusoidal) buckling load significantly. However, it increases the critical load, causing helical pipe configuration (helical buckling) of approximately 20%. The use of tool joints improved the efficiency of the axial load transfer by approximately 40%.

The results of this study will help to improve the design of operational parameters for drilling with jointed pipes as well as with coiled tubing (CT). In particular, improved axial-load transfer performance would allow drillers to use a higher weight on bit and, consequently, faster and possibly less costly drilling.
An Effective Continuum Model for the Gas Evolution in Internal Steam Drives
Authors: Tsimpanogiannis Ioannis N. , Yortsos Yannis C.
Published: December 2007

We derive an effective continuum model to describe the nucleation and subsequent growth of a gas phase from a supersaturated liquid in a porous medium, driven by heat transfer. The evolution of the gas results from the reduction of the system pressure at a constant rate. The model addresses two stages before the onset of bulk gas flow, nucleation, and gas-phase growth. The problem arises in internal steam drive—for example, of the type recently discussed in blowdown experiments in carbonate rocks (Dehghani et al.,1 Dehghani and Kamath2).

Important quantities, such as the fraction of pores that host activated sites, the deviation from thermodynamic equilibrium, the maximum supersaturation, and the critical gas saturation depend crucially on the nucleation characteristics of the medium. We use heterogeneous nucleation models in the form of pre-existing gas, trapped in hydrophobic cavities, to investigate the nucleation behavior. Using scaling analysis and a simpler analytical model, we show that the relevant quantities during nucleation can be expressed in terms of a simple combination of dimensionless parameters, which include rate effects. The subsequent evolution of the gas phase and the approach to the critical gas saturation are also described using numerical and analytical models.

The theory predicts that the maximum supersaturation in the system is a weakly increasing function of the decline rate. This function depends sensitively on the probability density function of the nucleation cavity sizes. It also predicts that the final nucleation fraction, and thus the critical gas saturation, is a power law of the decline rate. The theory for both nucleation and phase growth is then compared with available experimental data.
New Analytical Solutions for Predicting Pressure Distribution and Transient Behavior in Wedges and Truncated Wedges
Authors: Rahman N. M. Anisur , Bentsen Ramon G.
Published: December 2007

In most situations, predicting the pressure distribution and transient behavior becomes very difficult because of a lack of necessary mathematical solutions. However, analytical solutions are often used for such purposes, even though it may be necessary to compromise the geometry of the actual reservoir to obtain a solution. In this study, an integral-transform technique (ITT) has been used to develop new analytical solutions for pressure distribution in wedges and truncated wedges.
Optimization of Nonconventional Well Type, Location, and Trajectory
Authors: Yeten Burak , Durlofsky Louis J. , Aziz Khalid
Published: December 2007

The determination of the optimal type, location, and trajectory of a nonconventional well is extremely challenging. The problem is more complicated than other well optimization problems because of the wide variety of possible well types (i.e., number, location, and orientation of laterals) that must be considered. In this paper, a general methodology for the optimization of nonconventional wells is presented. The optimization procedure entails a Genetic Algorithm (GA) applied in conjunction with several acceleration routines that include an artificial neural network, a hill climber, and a near-well upscaling technique. The overall methodology is then applied to a number of problems involving different reservoir types and fluid systems. It is shown that the objective function (cumulative oil produced or net present value of the project) is always increased relative to its value in the first generation of the optimization, in some cases by 30% or more. The optimal well type is found to vary depending on the reservoir model and objective function. The effects of reservoir uncertainty are also included in some of the optimizations. It is shown that the optimal type of well can differ, depending on whether single or multiple realizations of the reservoir geology are considered.
Errors in History Matching
Authors: Tavassoli Z. , Carter Jonathan N. , King Peter R.
Published: December 2007

The usual procedure in history matching is to adopt a Bayesian approach with an objective function that is assumed to have a single simple minimum at the "correct" model. In this paper, we use a simple cross-sectional model of a reservoir to show that this may not be the case. The model has three unknown parameters: high and low permeabilities and the throw of a fault. We generate a large number of realizations of the reservoir and choose one of them as a base case. Using the weighted sum of squares for the objective function, we find both the best production- and best parameter-matched models. The results show that a good fit for the production data does not necessarily have a good estimation for the parameters of the reservoir, and therefore it may lead to a bad forecast for the performance of the reservoir. We discuss the idea that the "true" model (represented here by the base case) is not necessarily the most likely to be obtained using conventional history-matching methods.
Completion Design and Implementation in Challenging HP/HT Wells in California
Authors: Hahn D. E. , Burke L. H. , Mackenzie S. F. , Archibald K. H.
Published: December 2007

As producing companies search for significant hydrocarbon resources, it has become necessary to pursue opportunities in frontier geologic horizons and geographic locations. This pursuit frequently results in encountering high-pressure/high-temperature (HP/HT) environments. The petroleum industry defines HP/HT wells as those exceeding 10,000 psi and 300°F.

Several companies have drilled into HP/HT horizons in the California San Joaquin basin in the past 30 years, but operations were generally halted because of equipment limitations or limited hydrocarbon indications. In late 1998, a significant gas flow was identified from the Temblor formation at depths lower than 17,100 ft, with geologic information indicating a potential Temblor sand gross thickness of up to 3,600 ft. The pressure design basis for subsequent wells assumed an estimated equivalent pore pressure of 16.9 lbm/gal. This information and other producing conditions indicated a potential bottomhole environment of 425°F and 18,000 psi. Produced fluids also indicated the presence of hydrogen sulfide (H2S), which, at these pressures, dictates sour service metallurgical specifications.

These potential, extreme well conditions require a very detailed completion engineering design, equipment qualification, rigorous planning, and precise field execution to achieve successful well completions. This paper details and discusses the well completion design basis and issues, equipment/perforating limitations and qualification tests, tubular stress and loading analyses, high-density completion-brine usage, and actual field operational experiences.

Numerous contingencies were planned in detail, some of which had to be implemented. The most significant contingency operation was a high-pressure coiled-tubing milling operation to clean out 2,500 ft of formation and perforating debris that plugged the tubing string.
An Analytic Method for Producing Multiarray Induction Logs That Are Free of Dip Effect
Authors: Barber T. D. , Minerbo G. N.
Published: December 2007

Dip effect on induction-tool response is a well-documented and well-understood environmental effect that produces increased shoulder effect at moderate dip and a complete scrambling of multiarray induction logs at high dip. Although techniques such as maximum-entropy inversion allow a full correction of the logs, these remain computer-center products that are somewhat time-consuming. Wellsite inversion to correct for dip effect has remained elusive, waiting on more computer power.

In the mid-1960s, Pierre Grimaldi discovered an induction measurement technique that had the remarkable property of returning the same reading in a "thin" bed that it gave in an infinite, homogeneous medium of the same conductivity. The only requirement to satisfy this condition was that the instrument sensors were all in the thin bed. The instrument configuration was such that the voltage measured was a direct solution to Maxwell's equations. Although this was a breakthrough, the instrument configuration was difficult to realize in hardware, particularly with the well-logging technology of the 1960s, and the idea was never published.

The Grimaldi configuration was independently rediscovered in the early 1980s and studied with new modeling codes. It was found that the "remarkable property" of having no shoulder effect was also approximately true at any dip angle. Again, the hardware was deemed to be impractical.

More recently, it was discovered that the array configuration of the AIT* Array Induction Imager family of tools was such that the raw array-measurements data could be processed to be the same as those from a Grimaldi configuration. This led to a real-time algorithm, and a set of Grimaldi curves is now available at the wellsite. This algorithm produces synthetic arrays equivalent to a Grimaldi coil configuration that solve the inverse problem without having to solve Maxwell's equations iteratively.

The Grimaldi configuration is not without its drawbacks— nature is not so kind. The logs have a shallower depth of investigation than those from a conventional induction array of the same spacing. For this reason, the Grimaldi logs supplement, but do not replace, the standard AIT log sets.
An Openhole Memory-Logging System for High-Angle Wells and Bad Hole Conditions
Authors: Elkington P. A. S. , Spencer M. C. , Spratt D. L.
Published: December 2007

A mechanism for conveying logging tools inside drillpipe has been developed that reduces the risk and cost of acquiring openhole formation evaluation data in high-angle wells and bad hole conditions. The measurement string is housed inside drillpipe, where it is protected while running in, and pumped into open hole close to final depth. Wireline tools are used for data-quality reasons, but the wireline has been eliminated, giving time, access, and well-control advantages relative to wireline pipe-conveyed logging (PCL). It is an alternative to the formation evaluation element of logging while drilling (FE-LWD), where steering decisions do not rely on real-time petrophysical analysis, particularly when the risk to the bottomhole assembly (BHA) is high. The system's ability to acquire data while conditioning the hole contributes to its efficiency and is advantageous in bad hole conditions.

A 1.4-km horizontal test loop was constructed to help develop and prove the tool deployment and signaling mechanism. Insights gained during this process resulted in the development of novel payload delivery seals—key components in the system.

Formation evaluation data have been acquired in 220 wells; they include horizontal wells for which other logging solutions are unattractive for reasons of accessibility and/or cost. Knowledge gained from the interpretation of these data sets has influenced completions in some wellbores and guided remedial action in others.
Production of Pipeline-Quality Natural Gas With the Molecular Gate CO2 Removal Process
Authors: Wills James , Shemaria Mark , Mitariten Michael J.
Published: December 2007

In May 2002, the first Molecular Gate* Carbon Dioxide Removal system for the removal of carbon dioxide and water was started at the Tidelands Oil Production Co. facility in Long Beach, California. The feed source for the unit is hydrocarbon-rich, water-saturated, associated gas from waterflood enhanced-oil-recovery (EOR) operations. The feed CO2 concentration varies widely and is typically more than 30%, while the unit reduces the carbon dioxide level to less than 2%. The unit removes the carbon dioxide, heavy hydrocarbons, and water-producing pipeline specification gas for sale to the local natural gas utility company.
Three-Phase Flow WAG Processes in Mixed-Wet Porous Media: Pore-Scale Network Simulations and Comparison With Water-Wet Micromodel Experiments
Authors: van Dijke M. I. J. , Sorbie K. S. , Sohrabi M. , Danesh A.
Published: December 2007

The pore-scale physics of water-alternating-gas (WAG) injection is still not completely understood. We summarize the development of a 3D pore-scale network simulator for capillary-dominated three-phase flow in media where wettability varies from pore to pore. Reduction of phase continuity has required incorporation of multiple displacements for mobilization of disconnected phase clusters. WAG processes have been simulated, for which saturation paths are recorded along with statistics of phase pore occupancies and displacement mechanisms, showing the importance of multiple displacements. Furthermore, using 2D network simulations, we have modeled the WAG floods following primary drainage and initial waterflooding in a water-wet micromodel. Good qualitative agreement is found, in particular with respect to the displacement mechanisms occurring during the WAG cycles.
Development and Field Testing of a Core Barrel for Recovering Unconsolidated Oil Sands
Authors: Hildebrandt A.B. , Bridwell H.C. , Kellner J.M.
Published: December 2007

The rubber-sleeve core barrel was developed to improve core recovery from unconsolidated sands, where it is most difficult to obtain cores with conventional barrels. The use of a rubber-sleeve core retainer, together with other departures from usual design, has required a considerable amount of testing to prove its operability. Tests run in shallow experimental holes and in drilling wells in the U.S. and Venezuela have, to a large extent, proved the operation of the barrel. Internal mechanism troubles, such as sandbinding of the sleeve, have been largely overcome. Cores have been recovered from completely unconsolidated sands where conventional coring has almost been abandoned because of poor recovery. In addition to retaining the core until brought to the surface, the barrel gives a "packaged-as-cut" core, which is convenient for handling and transportation. In the initial work, drag blade cutters, roller cutters, and tungsten carbide insert cutters were used for cutting unconsolidated sands.

Further bit head development is presently being conducted using diamond heads in unconsolidated sands where shales, hard sands, and limestones are encountered in adjacent formations. This work should render the barrel capable of cutting and recovering most types of formations, possibly including broken and fractured formations. This development is being carried on in cooperation with a diamond bit manufacturer.

Introduction

For many years the oil industry has needed greater recovery of cores from unconsolidated formations. Conventional equipment has been used to core unconsolidated sands with little success. Specifically, a core barrel was needed which would recover unconsolidated sands in a condition that would give useful reservoir information.

Development of the Rubber-Sleeve Core Barrel

Basic Requirements of Unconsolidated Sand Coring

The basic need was defined as a core barrel that would obtain a continuous unconsolidated core with sand grains in place as deposited in the formation. A preliminary survey of coring equipment and search of the literature pointed out the weaknesses of conventional core barrels. Laboratory tests using unconsolidated sand in a metal tube simulated actual sand movement into the care barrel during conventional coring. In conventional barrels the core sometimes crumbles and bridges, or fails under compressive column action, becomes oversize, and wedges against the walls of the inner barrel.