bluuebunny/crossref_metadata_2025_split huggingface dataset:
Wellbore Stability Simulations for Underbalanced Drilling Operations in Highly Depleted Reservoirs
Authors: Parra J. G. , Celis E. , De Gennaro S. 
Published: December 2007

Summary
The need to increase productivity and to reduce drilling formation damage favors the use of underbalanced drilling technology. The main idea is to drill with equivalent circulating densities (ECD) that are less than the formation pore pressure and to avoid contact between the drilling fluid and the formation. In highly depleted reservoirs, pore pressures can be very low. Therefore, extremely low-density fluids, such as foams, are used to achieve circulating densities lower than the pore pressure. In such cases, the induced modification of the in-situ stresses has to be supported mainly by the rock, with little contribution from the drilling fluid pressure. In that sense, the application of underbalanced drilling depends on the mechanical stability of the drilled formation, among other factors. In general, poorly consolidated, depleted formations are not suited for that technology. This paper presents the wellbore stability simulation performed to establish the feasibility of using underbalanced drilling in highly depleted reservoirs in western Venezuela. The in-situ stress field and the mechanical properties of the formation were obtained. Pore pressure as low as 800 psi at 5,500 ft (2.7 lb/gal equivalent fluid density) was measured. The finite difference method and an elastoplastic constitutive model was used to obtain the new stress, deformation, and pore pressure distribution. The undrained condition (immediately after the wellbore is drilled) as well as the drained condition were analyzed. The analysis showed that horizontal wells could be drilled in an underbalanced condition with low instability risk. Following the recommendations, four horizontal wells were drilled in underbalanced conditions. Values as low as 2.0 lb/gal ECD were used to drill the wells, and no wellbore instability problems were reported. Production tests showed an enormous increase in the well productivity index in comparison with conventional overbalanced drilling.
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

Summary
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

SummaryThis 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

Summary
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

Summary
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

Summary
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

Abstract
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

AbstractSteamflooding 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

Abstract
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

SummaryThe 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.