bluuebunny/crossref_metadata_2025_split huggingface dataset:
Convective Transport of Propping Agents During Hydraulic Fracturing
Authors: Clark Peter E. , Zhu Qinsheng 
Published: December 2007

Abstract
Since the paper by Cleary and Fonesca in 1992, there have been several attempts to determine if convection is an important factor in proppant placement. Papers by Clark and Courington, Clark and Zhu, and Barree and Conway have provided important clues, but the primary question remains unanswered. To address these questions, we have returned to the question of scaling in models. As mentioned in JPT paper (March 1995) by Clark and Zhu, scaling in a slot-flow model is difficult because each of the possible scaling factors (Reynolds number, velocity, shear rate and pressure drop) have a different dependence on width. Because of this, our initial laboratory model was scaled on shear rate and therefore flowing viscosity. Further examination of the problem lead us to believe that the ratio of the forces available to push the fluid in the horizontal and vertical directions is extremely important in determining whether or not convection is observed. This paper will discuss the development of two dimensionless groups that can be used to predict convection and the experimental evidence that validate these dimensionless group.

Introduction
Hydraulic fracturing is used as a primary stimulation technique for oil and gas wells. During a fracturing treatment, fluids are pumped under pressure through perforations in the pipe and into the formation. At some point the formation fails and the resulting crack is usually vertical and normally propagates away from the wellbore as two cracks 180 apart. A propping agent, such as sand, is pumped with the fluid to hold the crack open after the fracturing treatment is completed. When discussing fractures, the literature usually only deals with one wing of the fracture. A schematic of one wing of a fracture is shown in Figure (1).
Often the fracture is higher than the producing interval. When the fracture height is much higher than the perforated interval (see Figure (1)), the flow into the fracture can be classified as flow into a slot from a point source. In 1992, Cleary and Fonseca postulated that, in point-source fractures, gravity driven motion of the slurry, which they termed convection, will dominate Stokes type settling in the placement of the propping agent (Figure (2)). This is important because the placement of proppant within the productive interval determines, in part, the amount of production increase.
Unfortunately, while the speculation by Cleary and Fonseca was not supported by creditable experimental evidence, it was accepted almost without question by the industry. Since the concept of convection was proposed by Cleary and Fonseca, there have been a number of papers published on the subject. Clark and Courington published some initial results from a small slot-flow model. This work was followed by a more extensive study by Clark an Zhu and Barree and Conway.
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Experience on Horizontal Well Applications for Heavy Oil Fields
Authors: Araque-Martinez Aura , Aquiles Rattia R. 
Published: December 2007

Abstract
Maraven has evaluated the application of horizontal wells to enhance productivity and economics of their major heavy oil fields. Improving primary recovery on these heavy oil fields is important since it will allow postponing the implementation of more costly displacement processes such as steam drive.
Primary recovery includes not only Cold Production but also Cyclic Steam Stimulation (CSS). So far, two horizontal wells have been drilled in the Zuata area of the Orinoco Belt and four in the Bolivar Coast area. Several problems such as: sanding, completion design, formation damage and steam distribution have been reported. However, preliminary results show the benefits of the application of this technique in these heavy oil reservoirs.
Dead oil viscosity in these areas ranges from 1000 cp. to 20000 cp. at a temperature of 100°F. Cold production from a horizontal well is about 3 to 5 times the response of a vertical well, while the hot production rate is about 3 times of that reported from a steamed vertical well. The cost of a horizontal well is double the cost of a vertical well in the same areas, which makes a good net present value out of this project. Based on these results, plans have been laid down to extend the use of this technology.
Torsional Load Effect on Drill-String Buckling
Authors: Wu Jiang 
Published: December 2007

Abstract
Torsional loads on drill strings can reduce the axial compressive load limit for buckling the drill string. The larger the torsional load, the lower the buckling load. This paper presents a new analysis of drill-string buckling under axial compressive and torsional loads. New equations for buckling loads and lengths are derived for drill strings in vertical, inclined, horizontal, and curved wellbores.
The new analysis includes a model of the work done by the torsional load in the buckling process and provides a better understanding of drill-string buckling under the combined compressive and torsional loads. The results also agree with a previous study for horizontal wellbores.
With the new equations, drill-string buckling, drag, and torque can be predicted more easily and accurately for drilling horizontal wells. An example calculation is provided to illustrate the use of the equations for predicting drill-string buckling while rotary-drilling horizontal wells.
Optimization of the Performance of Partially Completed Horizontal Wells
Authors: Retnanto A. , Economides M. J. , Ehlig-Economides C. A. , Frick T. P. 
Published: December 2007

Abstract
Goode and Wilkinson (1991) have presented an analytical solution for the performance of a partially completed horizontal well. In that work they suggested that normalized well performance (compared to the idealized open-hole equivalent) can be favorably disproportional to the fraction of open well, especially if the total open length is distributed among several spaced intervals.
This work, using a comprehensive multi- and single-well semi-analytical well performance model, extends the Goode and Wilkinson results examining various open lengths, reservoir thicknesses and permeability anisotropy ratios. Both transient and late-time (pseudosteady-state) results are shown. It appears that the number of segments where the normalized productivity index flattens out is about four for almost all thicknesses. For thinner reservoirs the relative impact from the number of segments is more pronounced. For example, for a thin (20 ft) isotropic reservoir, 40 % of open well, of 2000 ft total length, distributed in four segments, would lead to almost 90 % of the open-hole equivalent productivity index. For thicker reservoirs and/or longer wells the incremental productivity index fraction decreases. The idea of a sequence of open/close segments, accomplished either by perforated and non-perforated or slotted/blank liners has merit for zonal isolation, future well management and problem remediation. Economic calculations, incorporating production and well completion including zonal isolation devices show substantial attractiveness from partially completed, segmented horizontal wells.
Motor Power/Current Measurement for Improving Rod Pump Efficiencies
Authors: McCoy J. N. , Podio A. L. , Ott Russ , Rowlan Lynn , Garrett Mark , Woods Mike 
Published: December 2007

ABSTRACT
The development of accurate digital measurement of instantaneous power during a pump stroke has made possible a very quick and detailed analysis of the efficiency of the pumping system. The efficiency is then used as the benchmark for determining whether a complete well performance analysis is warranted from the standpoint of making best use of personnel and economic resources to increase oil production.
In addition, power measurement provides direct information about lifting cost per barrel of fluid and barrel pf oil produced, electrical and mechanical loading of the prime mover, peak power demand, power factor and minimum required ratings. These results give operating personnel information regarding potential problems and give to management a complete picture of the distribution of pumping costs.
The power measurements are also converted, by the software, to instantaneous torque and presented as continuous torque curves for the upstroke and downstroke. This allows determination of the existing level of counterbalance and provides the most rapid and accurate method for counterbalance adjustment to achieve lower torque loading on the gear box and reduced energy utilization. One of the principal advantages of this balancing method is that counterbalance adjustment can be made without need for an accurate description of the pumping unit's geometry which is often unknown or inaccurate. The effect of counterweight displacement on torque and power is observed immediately by repeating the power measurement after relocating the counterweights.
This paper presents a series of case studies showing the application of power measurement to a variety of pumping systems and components, including conventional, Mark II, Rotaflex units and high efficiency motors.
Split Flow Steam Generator Solves Water Treatment Problem and Pressure Limited Throughput Problem in South Belridge
Authors: Mitchell J. B. 
Published: December 2007

Abstract
Some oilfield operators have experienced a marked increase in steam generator catastrophic tube failures due to changes in water quality reaching the steam generators and aging of the steam generators. One operator in the South Belridge Field has been replacing one-third to one-half of the radiant tubes in each steam generator every year for several years. In addition, some operators have been limited trying to increase steam generator throughput by both the steam generator's design and other interrelated facilities. Minor piping and control system changes allow the conversion of a typical 50MMBtu/hr steam generator's radiant heat recovery section from a design of one (l) single water/steam pass to a design of two (2) parallel water/steam passes. The result is that the water/steam mixture has half the distance to traverse in the radiant section and does so at half the velocity. The water quality problem or steam generator aging problem seems to benefit from the reduced velocity since no tube wall loss has been detected in six (6) months on steam generators receiving this change. In addition, since pressure loss depends on length and velocity to the second and third powers, lower pressure drop in the radiant section has allowed significant increases in steam generator throughput thus lowering unit steam costs. Here a simple mechanical change in the steam generator provided a solution that was uneconomical to address chemically or with other facilities.
Comparative Effectiveness of CO2, Produced Gas, and Flue Gas for Enhanced Heavy Oil Recovery
Authors: Srivastava Raj K. , Huang Sam S. 
Published: December 2007

Abstract
A large number of heavy oil reservoirs in Alberta and Saskatchewan are thin and marginal and thus unsuited for thermal recovery methods. For these reservoirs, immiscible gas displacement appears to be a very promising enhanced oil recovery technique for these heavy oil reservoirs. This process, if proven applicable, will access 90% of Saskatchewan's initial-oil-inplace. This paper discusses results of a laboratory investigation for assessing the suitability and effectiveness of three injection gases for heavy oil recovery. The gases investigated were a flue gas (containing 15 mol% CO2 in N2), a produced gas (containing 15 mol% CO2 in CH4), and pure CO2. The test heavy oil (14° API gravity) was collected from Senlac reservoir located in the Lloydminster area. The evaluation was based on PVT studies, coreflood experiments, scaled model tests, and numerical simulations. In this paper, the focus is on the first two.
PVT studies indicated that the important mechanisms for Senlac oil recovery by gas injection were oil viscosity reduction and oil swelling. Pure CO2 appeared to be the best recovery agent, followed by the produced gas. The coreflood results confirmed these findings. Nevertheless, produced gas and flue gas could be sufficiently effective flooding agents. They showed oil recoveries only 2 to 4 percentage points lower than those obtained with pure CO2 (exceeding 45% initial oil-in-place). Comparable oil recoveries in flue gas or produced gas runs were believed to be a combined result of two competing mechanisms – a free gas mechanism provided by N2 or CH4 and a solubilization mechanism provided by CO2. This latter predominates in CO2 floods.
Armada Development: Case History of Extended Reach Pre-Drilling from a Semi-Submersible in the Central North Sea
Authors: Teggart B. G. , Dunne C. L. , Wilkinson R. D. 
Published: December 2007

Abstract
In February 1995, the development of the British Gas E&P operated Armada field commenced when the semi-submersible Santa Fe 135 was positioned over a previously installed ten slot template and pre-drilling commenced with the objective of drilling and suspending eight wells ready for tieback and completion from the jacket and topsides to be installed in March 1997. The nature of the field development, with a centrally located platform, coupled with the multiple reservoir objectives in the Palaeocene and Jurassic, resulted in an extremely challenging pre-drilling programme involving extended reach drilling and evaluation, and potentially a new world record for the longest well drilled from a semi-submersible. The average measured depth and step out of the eight wells were 18508 ft and 13830 ft respectively, with inclinations ranging from 60 – 75 degrees. The surface casing strings were successfully batch set on all eight wells for operational efficiency. Performance in the early wells was plagued by borehole stability problems and equipment failures. Despite these difficulties, the objectives were realised, and later performance has been exceptionally good. The Armada pre-drilling experience demonstrates that performance extended reach drilling can be achieved with a third generation semi-submersible by detailed planning, motivation of the "drilling team" and careful attention to detail.
Pressure Integrity Test Interpretation
Authors: Postler D. P. 
Published: December 2007

Abstract
A Pressure Integrity Test (PIT), sometimes called a leak-off test, is a field practice used to evaluate cement jobs and estimate the formation fracture gradient. Interpretation of the PIT becomes the basis for critical well decisions such as cement job evaluation, casing setting depths, mud weights, and well control alternatives. Incorrect interpretation of the PIT can lead to unnecessary squeeze jobs, premature setting of casing, lost circulation, or other costly problems that could jeopardize well progress.
The shape of the PIT plot and the leak-off pressure are primarily governed by the local stresses at the wellbore wall. However, a number of other factors can distort PIT results and lead to interpretation difficulties. This paper explains how these factors can influence the PIT and shows how to interpret PIT plots and differentiate between cement problems and formation effects. Field examples are given to demonstrate the practical application of simple guidelines for PIT interpretation. The paper also presents guidelines for procedures to help ensure a valid PIT.
High Penetration Rates: Hazards and Well Control—A Case Study
Authors: Frigaard I. A. , Humphries N. L. , Rezmer-Cooper I. M. , James J. P. 
Published: December 2007

Abstract
Good agreement with field data has been obtained when using a commercial kick simulator to analyse a 56 bbl gas kick taken in a 59 deg deviated wellbore.
Fast kick detection and reaction are necessary when drilling at high rates of penetration since high pump rates, necessary for hole cleaning and cuttings transport, imply that a gas influx may be rapidly circulated to surface. A simulated example of a field kick is used to show how close to a blowout it is possible to be with normal rig actions and response times; the tip of the gas cloud is less than 300 ft below surface and rising fast at shut-in. Benefits of earlier detection and shut-in are illustrated through simulation.
High penetration and pump rates result in dispersal of the influx along the annulus. This makes kick detection harder, since a greater proportion of the influx gas can dissolve in the drilling fluid. A simulated example emphasizes how influx detection can be significantly harder with an oil based mud than with a water based mud.
Gas migration results in a stabilised bottom-hole pressure much higher than the formation pore pressure. Subsequent use of standard field methods significantly overpredicts kill mud weight: alternative interpretation methods are suggested.
Based on the results of the simulations, procedural recommendations are made in order to minimize the risk of a kick and to enhance the probability of kick detection.
Circulation is dangerous if a potential influx could be pumped a significant distance up the annulus during the period of circulation. So, when making a connection, dangerous periods of circulation should only be carried out after completing the connection.
When the influx is dispersed along the annulus, surface pressures may take a long time to stabilise. Prompt use of the driller's method in these cases gets the gas safely out of the wellbore and lessens possible misinterpretation of shut-in pressure rise.
Using simulation for well control contingency planning can help in early recognition of field hazards and in the confident choice of appropriate actions.
Drilling Index—A New Approach to Bit Performance Evaluation
Authors: Perrin V. P. , Mensa-Wilmot Graham , Alexander W. L. 
Published: December 2007

Abstract
The drilling industry has seen tremendous improvements in drill bit development and performance’. Technological advancements are being made by bit manufacturers in order to meet the continuously changing and more demanding needs of operators2-'4. Bits now stay in the hole longer and drill faster. Within this context, it is also worth noting that the application envelopes of all types of bits have expanded4-'6. Bit technology has evolved and continues to advance to meet the challenging needs of today's drilling industry.
However, the means of evaluating drill bit performance improvements have not kept up with advancements in technology. Methods such bit factor, formation drillability, mechanical specific energy and cost per foot continue to be used for bit performance evaluation7. Although cost per foot is the most accepted method, its effectiveness has drastically been overshadowed by today's drilling needs and bit technology.
This paper will present the Drilling Index (Dl), as a new approach to bit performance evaluation. It draws on the strengths of the older methods and establishes cost per foot as an indirect evaluation tool. Dl benefits from the greater understanding that has been gained by the bit industry with regard to product development and application. It defines performance, behavior, directional responsiveness and steerability as dimensionless parameters that reflect the operator's needs as well as the bit manufacturer's technological strengths.
Imperial's Steelman Unit IA And II Waterflood System
Authors: Stevenson D.W. 
Published: December 2007

Publication Rights Reserved
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and considered for publication in one of the two SPE magazines with the paper.

Abstract
In Jan., 1962, full-scale water flooding began in the Steelman field of southeastern Saskatchewan. The field has been developed on 80-acre spacing and the injection pattern is an inverted nine-spot. The main requirements of the flood are a high quality water and flexibility in injection rates and pressures. To accomplish these ends water from the high capacity Blairmore sand is distributed to the injection plants, where it is filtered and inhibitor-treated, before injection into high pressure lines radiating to the injection wells. The pressure and rate of injection to each well is controlled at the injection plant. Plant operation is semi-automatic and source well pumps, filters, engines and injection pumps are protected by safety controls. Corrosion throughout the injection system is controlled through coatings and inhibitor and bacteriacide injection.
The design of the injection system was influenced by the results of a pilot operation which commenced in 1958. The use of dry gas engines and diatomaceous earth filters are some of the design improvements derived from pilot experience. This presentation discusses the design of surface facilities for the water floods in Steelman Units IA and II, which were installed by Imperial Oil, Ltd. in 1961.

Introduction
The Steelman field is on the northern rim of the Williston Basin in southeast Saskatchewan, approximately 15 miles north of the International Boundary, Fig. 1. The reservoir, at an average depth of 4,700 ft, is a stratigraphic trap of Mississippian limestone known locally as the Midale Beds. The zone is thin and heterogeneous with low permeability. To date, 760 wells have been drilled on 80-acre spacing. Recovery has been estimated at 16 per cent under natural depletion and 35 per cent under water flooding.
Before fall-scale water flooding could be undertaken in Steelman, a pilot test was considered necessary because of the tight and heterogeneous nature of the reservoir, and the presence of hairline fractures which had been observed in cores throughout the field. To permit rapid evaluation, a closely spaced five-spot pilot pattern was selected with four injection wells drilled in the 10-acre area surrounding an existing producing well. Because of diverse lease ownership, a nine-section area was unitized to accommodate the pilot test. Unit negotiations were completed and water injection commenced in 1958. While essential reservoir data were being collected, the design and operation of the installed waterflood equipment was evaluated.
The Economical and Technical Advantages of Low Head Drilling of Depleted Reservoirs with Aerated Mud: A Case History Offshore Angola
Authors: Zurdo C. , Gazaniol D. , Grepinet D. , Ybert J. , Rodrigano R. 
Published: December 2007

Abstract
The additional development of an offshore oil field located in the Angolan waters required to drill through the highly depleted producing Pacassa/Buffalo reservoir (0.7 specific gravity at a 3600m vertical depth). Heavy losses and frequent drill string sticking resulted from the use of conventional muds during the initial development wells. Low head drilling with aerated mud and jointed pipes was then used on the subsequent wells with encouraging and improving results and consequent costs reductions.
The drilling fluid was a mixture of a bentonitic water base mud and air, injected inside the drill string which was equipped with two jet subs positioned in the Bottom Hole Assembly at approximately 1200 and 1500m. An empirical method was used to determine and control the proper mud and air flow rates which were necessary to ensure the right combination between well control and drilling performances. This method was based on field experience and was improved through the lessons learned during the whole operation.
A Novel High-Pressure Rotary Shaft Seal Facilitates Innovations in Drilling and Production Equipment
Authors: Kalsi M. S. , Conroy W. T. , Dietle L. L. , Gobeli J. D. 
Published: December 2007

Abstract
This paper describes the principle of operation, laboratory test results, and field performance of a novel high pressure rotary shaft seal and the key features of implementations which have made a number of oilfield drilling and production equipment innovations technically and economically feasible in recent years.