bluuebunny/crossref_metadata_2025 huggingface dataset:
Convective Transport of Propping Agents During Hydraulic Fracturing
Authors: Clark Peter E. , Zhu Qinsheng
Published: December 2007

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

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

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

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

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

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

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

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

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

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

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.

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

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

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.
Evaluation and Selection of Petroleum Engineering Software: A Case Study
Authors: Eldin O. Nasr , Hussein A. , Kumar S. , Ashry A.
Published: December 2007

Recent advances in computer technology and the proliferation of computers in the workplace have had a big impact on technical decision making and on the day to day work of engineers. In petroleum engineering, we are faced with a variety of complex software, with different functionalities, prices and features. It is quite a challenge to review the options available and to select one which will be the optimum for a significant length of time and provide the company with best tools at the lowest price.

This paper presents the philosophy and the methodology involved in the evaluation of software. The compulsions on the part of the suppliers as well as the demands of the customers are discussed. Practical criteria for evaluating software for petroleum engineering applications, evolved through the last decade of experience in several operating companies and with discussions with international suppliers and experts, are presented.

The process of evaluation and the criteria and process of selection are described through two real examples, one for reservoir simulation software and the other for well test analysis software, undertaken recently at our company. Detailed tables and check-lists are presented for these two cases which enabled the engineers as well as the management to quickly review the available packages and to decide which one would best meet their needs. A desirable outcome of the process was the fact that we were able to provide the suppliers with a lot of sensible suggestions to improve their products for our benefit.

This paper seeks to provide an understanding of the software process lifecycle, from design to sales to usage, in order to allow engineers the necessary insight for evaluating their own given software.

The software industry is in such turmoil that these skills are now necessary on a frequent basis for continuous quality improvements which require that engineers find the best solutions to their problems at lowest cost.
Vertical Capillary Continuity Between the Matrix Blocks in a Fractured Reservoir Significantly Improves the Oil Recovery by Water Displacement
Authors: Pratap Mahendra , Kleppe Jon , Uleberg Knut
Published: December 2007

Block to block processes in a vertical stack of matrix blocks in a fractured reservoir have been extensively studied for gas-oil systems. Similar investigations have, however, not been reported for the case of water-oil systems. This study details the block to block processes and the effect of capillary continuity between the matrix blocks on oil recovery by water displacement in a fractured reservoir. Fine grid simulation studies under water flooding have been carried out on Eclipse 100 for varying degrees of matrix to matrix contact to illustrate the dependence of oil recovery on the position and the extent of the areal contact between the matrix blocks. Our results show that for the simplified system of mixed wet matrix blocks, the phenomenon of oil re-drainage from the downdip blocks to the updip blocks takes place both with or without matrix contacts between them. Such a phenomenon is not observed in case of strong water wet rock. For strong water wet rock, capillary imbibition controls the oil recovery and the effect of capillary continuity is not significant. However, for reservoirs of mixed wettability, such as Ekofisk, the oil recovery is significantly enhanced even with a moderate areal contact between the matrix blocks. The additional oil recovery, which is substantial as compared to the isolated single matrix block oil recovery, is due to gravity forces and depends on the thickness of the payzone. The oil recovery and the recovery time are also dependent on the tortuosity of the capillary continuity.

The findings of the study have applications in the prediction of oil recovery by water displacement in a fractured reservoir.
Nuclear Logging-While-Drilling Measurement: An Assessment
Authors: Badruzzaman A. , Nguyen P. T. , Stonard S. W. , Logan J. P.
Published: December 2007

The state-of-the-art in nuclear logging-while-drilling measurements is discussed. Recent improvements in design and interpretation to address the difficulties encountered by these measurements in the dynamic borehole environment that exists are described. Examples of evaluation of the measurement from field data are given. Use of three-dimensional Monte Carlo modeling techniques to complement field measurements in assessing these measurements is illustrated.
Tertiary Miscible Flood in Phegly Unit, Washington County, Colorado
Authors: Connally C.A.
Published: December 2007

This paper was prepared for the Improved Oil Recovery Symposium of the Society of Petroleum Engineers of AIME, to be held in Tulsa, Okla., April 16–19, 1972. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.

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, with the paper, may be considered for publication in one of the two SPE magazines.

A slug of LPG followed by slugs of natural gas alternated with water and finally driven by further water injection was used in a miscible displacement scheme for tertiary recovery in the Muddy D sand reservoir, Phegley Unit, Washington County, Colorado. The tertiary project was applied full-scale to the small (9.6 MM bbl PV) reservoir at a time when a successful waterflood was approaching completion. An additional bank of oil was produced but the oil rate declined rapidly with premature gas breakthrough. It was concluded that the volumetric sweep with the miscible fluid was relatively inefficient because of an unfavorable mobility ratio. Also, it was possible that a significant portion of the oil banked-up within the reservoir was bypassed after breakthrough of gas at the production wells.

Introduction

As with most successful waterfloods, the Phegley Unit operation was leaving more than half of the original oil in place as it approached the economic limit. Wells and production equipment were in generally good condition, there were no adverse problems with fluid injection, injection and production volumes were essentially equal and flooding performance had been good. The Unit appeared to be a favorable site for a trial of some technique for tertiary recovery.

A variety of methods were considered for improving recovery, including carbon dioxide injection and thermal techniques. A miscible displacement sequence involving a slug of LPG followed by slugs of natural gas alternated with water was chosen as having the best potential for success in this particular situation. The relatively small size of the reservoir allowed risking a reservoir-wide trial rather than a single pattern pilot test. The tertiary recovery operation was begun in September, 1964 and the following discussion describes the performance through July, 1971.

SITE CHARACTERISTICS AND PRIOR HISTORY

The Phegley Unit is located about 90 miles east of Denver in Washington County, Colorado. Production is from the Muddy "D" sandstone of Cretaceous age. The sand averages about 8 ft thickness and extends over an area of about 785 acres. Depth averages about 4900 ft.
Analytic Technique to Forecast Production for Non-Declining Oil Wells in Bounded Solution-Gas-Drive Reservoirs
Authors: Sonrexa Kartikay , Kumar P. Santhana , Al-Ajmi Hussain
Published: December 2007

A methodology has been developed to forecast the performance of an oil well which has not gone into the decline mode as yet i.e., which is exhibiting (a) increasing, (b) constant or (c) fluctuating production rates. This procedure has been adapted from the solution of the familiar "Diffusivity Equation" under conditions which give rise to the well-known "exponential decline" behavior. The technique has been illustrated with the help of both a synthetic case and an actual field example from a Middle Eastern reservoir. The analytically-derived predictions have been compared with the results from single well numerical simulation. There is good agreement between the two. The analytic technique gives conservative predictions.

Introduction

Historically, one of the most common tasks that a petroleum engineer is confronted with, while analyzing the performance of a single well, a reservoir or a field is the determination of :Future production rates;Producing life and,Remaining reserves before reaching its economic limit.

One may require the knowledge of these quantities both for a mature producing field as well as a newly-discovered one. These parameters have a large impact on important financial decisions. Numerical simulation provides a means to calculate them through modeling the well/reservoir/field. However, the process of modeling can be quite time-consuming and expensive. It is, therefore desirable to develop analytic means to furnish quick yet reliable answers.

The technique most often employed to derive the above quantities is the so-called "Decline Curve Analysis" which is applicable during the declining production phase. The procedure essentially consists of (i) plotting oil production rates versus time, (ii) establishing a trend through the past performance by fitting a suitable curve and (iii) extrapolating the curve to make forecasts. It has been recognized for a long time that the decline curves can be of three types :Exponential,Hyperbolic andHarmonic.

Originally it was believed that the curves were purely empirical in nature with the hyperbolic curve representing the most general type whereas exponential and harmonic curves were special cases when the "decline exponent" was equal to zero or one, respectively. In recent times, it has been demonstrated that the exponential type of decline does, indeed, have a sound theoretical basis. Constant-pressure solution of the radial Diffusivity Equation for a well in a bounded reservoir under the well-known standard or ideal conditions e.g., single phase fluid, laminar flow etc. proved to be an exponential decline during the pseudo-steady state regime.

Discussion

The topic of decline curves has been vigorously debated in the petroleum literature since J.J. Arps proposed his famous equations. P. 61^
Microbial Induced Corrosion Of Subsea Pipeline in the Gulf Of Suez
Authors: El-Raghy Saad M. , El-Leil Hussein M. Abou , Ghazal Hany H.
Published: December 2007

In mid May, 1996, a leak was developed in a 24" crude oil line which transfers the untreated crude oil from El-Morgan field at Gulf Of Suez to the onshore process facilities. The line was installed in April, 1993 from carbon steel, API-SL XS - 60, tubing with wall thickness 0.75 inch. A diving survey was carried out after oil spill using side scan sonar survey and an Remote Operating Vehicle (R.O.V) video inspection identified the leak to be due to internal corrosion in 8 joints located at depth 240 - 250 feet. After fixing the leaks, complete ultrasonic survey was performed using high resolution intelligent pig. The ultrasonic data with the sample analysis of the deposits accumulated a head of the pig confirmed the mode of corrosion as internal Microbial Influenced Corrosion (MIC) in 6 o'clock position. A comprehensive review of the corroded line history and the available corrosion monitoring data and the applied corrosion mitigation program refereed to the following:Corrosion monitoring using weight loss coupons, electrochemical devices, and / or chemical methods installed in the two ends of the subsea pipelines does not shows any sign of high corrosion rate (average 3 MPY).Absence of frequent pigging process in the pipeline resulted in accumulation of sludge that caused under deposits corrosion.Thermophilic SRB bacteria was not detected, however some non SRB's were detected.

This paper reviews in details the pipeline history, corrosion mechanism, inspection outlines, reservoir souring modeling and presents action plan to prevent this leak to happen again in future, with a brief introductory for mitigation options strategies and economics

Introduction

The Gulf Of Suez Petroleum Company (GUPCO) was founded in 1965 as a joined venture company between the Egyptian General Petroleum Corporation, EGPC, and the standard oil company, AMOCO, For oil exploration and production in Egypt. The production reaches its prehigh in early 1985 with total 600,00 bbls oil per day. However, production started to go down due to normal reservoir depletion and limited new discovers.

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A New Conventional Method of Analysis for Well Tests in Hydraulically Fractured Wells Using Downhole Pressures and Sandface Rates
Authors: Osman Mohammed E. , Almehaideb R. A. , Abou-Kassem J. H.
Published: December 2007

Analysis of variable flow rate tests has been given special attention recently because, in many cases, it is impractical to keep a flow rate constant long enough to perform a drawdown test. Also, in many other drawdown and buildup tests, the early data are influenced by wellbore storage effects, and the duration of these effects can be quite long for low-permeability reservoirs. For hydraulically fractured wells, the early-time period represents linear flow. Current methods of analysis of multirate tests, in fractured wells, use both conventional and rate-normalized type-curve matching for the pseudoradial flow period; and only rate-normalized type-curve analysis for the linear flow period. None of the current methods use a direct approach to analyze the linear flow data.

This paper presents a mathematical model which describes drawdown and buildup tests in hydraulically fractured wells. A new conventional and simple method of analysis based on this model is presented for drawdown and buildup tests in oil and gas wells. This new method uses a direct approach to analyze the linear flow data and combines it with the conventional analysis for pseudoradial flow data. It does not require a priori knowledge of the fracture type (uniform-flux or infinite-conductivity); in fact it predicts the fracture type.

This method is useful for the analysis of simultaneously measured downhole pressure and sandface rate data.

Data of three well tests reported in the literature were analyzed by the new method and the results including the comparison with those obtained by other methods are presented and discussed.
Tying Training to Business Needs (Case Study)
Authors: Wadoud H.A. , Khalaf Fouad
Published: December 2007

The new training process is centered around "tying training to business needs" as defined in the Company's mission, vision and values. A performance management form is used to identify training requirements related to Company business. The new process adds the following features:–Introducing the concept of having a training coordinator, fully assigned to this task if necessary, in every major department to help supervisors identify training requirements for employees–Having a short- and long-term evaluation process, used for the first time in Egypt, to scorecard training benefits for verifying that training costs have their yields on the actual business–Having a central training team to coordinate efforts for a final plan, to optimize the process, manage cost, and propose improvements in the new process–Establishing a comprehensive training database–Clarifying process and roles for defining needs, getting approvals, and evaluating the business returns from training.

This paper presents Gupco's efforts to improve training and to tie it to business needs; shows the components of the new training process and the implementation problems; and finally highlights future directions and developments in order to enhance tying training to Gupco needs for improving business practices.

Gupco's efforts in the training field can help external customers (training institutions and universities) define their products in order to address Gupco training requirements and will help achieve win-win deals between the Gupco and its business partners in the "training industry." The efforts achieved in Gupco address an international concern about strengthening co-operation between partners in training: industries, universities and training firms.

Introduction

Improving employees' skills and competencies and preparing them for future careers is basic for progress of any organization. Organizations need to create an environment that encourages learning. Professional organizations which want to be leaders in the industry should be "learning organizations," willing to address current and future training needs. Only by doing this, organizations shall develop the power and the human resources to survive and thrive the turmoil of the future and be able to successfully make the transition to the 21 century. Today's professionals are expected to have adequate knowledge of everything that is related to their core business: they need to learn business management, system thinking, mind mapping, how to read fast and to improve communication skills, how to re-educate self and how to absorb information.

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Inert Gas Injection as Secondary and Tertiary Recovery Method in the Martha Field in Kentucky
Authors: Vadgama Usman N. , Hinkle Bill B.
Published: December 2007

To study the economic feasibility of an inert gas injection process in the low-permeability portion of Martha field, a pilot project was portion of Martha field, a pilot project was initiated in Dec., 1966. During 3 years of operation - from 1967 to 1969–77 MMscf, or 20.6 PV, of inert gas have been injected into the formation. PV, of inert gas have been injected into the formation. As of this date, approximately 12,000 bbl of additional oil have been recovered. Another 5,000 bbl of "inert gas oil" are expected before the production declines back to its initial rate. Calculated additional oil recovery is about 33 bbl/acre-ft. Inert gas injection per barrel of oil production amounts to approximately 4.5 Mscf. Before going to a full-scale injection program, a second pilot was initiated to study the effectiveness of this process, in combination with cross flooding, in process, in combination with cross flooding, in a watered-out low-permeability area where waterflooding was ineffective. First results obtained are encouraging. The cost for generation and compression of inert gas is estimated to be 120/Mscf.

Introduction

Eastern Kentucky is one of the old oil-producing areas of the U.S. The first known well to produce petroleum was drilled in 1830 in Knox County. Fig. 1 shows geographic locations and geological formations of main oil- and gas-producing areas of Kentucky.

The Martha oil field is located just northeast of the junction of Johnson, Lawrence and Morgan Counties, and is shown with an arrow in Fig. 1. The field was discovered in 1919 and covers approximately 4,500 acres. Since then, the Martha oil field has produced roughly 19 million bbl of oil primarily by gas-in-solution type reservoir energy. As the reservoir energy declined, a waterflood project on the east side of the field was started in 1955. As of this date, approximately 2,300 acres in the main area of Martha field has been developed for and is presently maintained under active water injection. Over 6 million bbl of secondary oil has been recovered during the last 15 years. The expansion of waterflood to an additional Ashland-owned 1,100 acres was limited because of low injectivity. This low-permeability portion of the Martha field has produced 4.7 million bbl of primary oil, which represents roughly 127 bbl/ acre-ft, or 15 percent of initial oil in place. In other words, over 30 million bbl of oil remains unrecovered in the ground. This huge amount of oil is a big challenge to us and offers an opportunity to test the field-wide application of one of the improved oil recovery techniques.
A Study of the West Cement Medrano Unit - Caddo County, Oklahoma
Authors: Hall Alvin E.
Published: December 2007

This paper presents a study of the operation of the West Cement Medrano Unit in Caddo County, Okla. Included are essential data on reservoir characteristics, history of development, and reservoir performance, under both competitive and unitized gas injection operations.

Introduction

The West Cement Medrano Pool produced from a gas cap above an oil reservoir for 6–1/2 years before oil was discovered. It was then produced for 4 1/2 years as a combination pool with both gas and oil wells producing on a competitive basis. The gas wells were voiding several times as much reservoir space as were the oil wells, and it was recognized that should this situation continue, the gas wells would soon deplete the reservoir pressure and only a part of the oil reserve could be produced. The pool was unitized on Dec. 1, 1947, and all gas wells and high ratio oil wells were immediately shut in. Selective production operations continued until a gas compression plant was completed in July, 1949, and first gas was returned to the reservoir. Since this date, the pool has been operated under pressure maintenance with all produced gas and water returned to the reservoir.

History of Development

The West Cement Medrano Unit is located in Townships 5N and 6N, Ranges 9W and 10W, Caddo County, Okla., 70 miles southwest of Oklahoma City and 10 miles directly south of the city of Anadarko on State Highway No. 8. Geologically, the field is located near the trough of the Anadarko Basin, and deep wells drilled in the area indicate the presence of sedimentary beds and possible oil production to depths of over 20,000 ft. The Medrano Sandstone is one of some 25 or more formations which produce oil and gas in the Cement Area.

The Medrano Sand was first found productive in a well drilled by Magnolia Petroleum Co. in the SE NE SW of Section 36-6N-10W. This well, Magnolia's Medrano No. 6, found 67 ft of gas saturated sand and was completed at a plugged-back total depth of 4,950 ft for an open flow potential of 78.1 million cu ft/D. At the time the well was completed, there were several dry gas reservoirs producing in the Cement Area, and it was believed that the newly discovered Medrano Reservoir was also a dry gas reservoir. Additional wells were drilled to the Medrano on wide spacing, and for the first 6–1/2 years, the reservoir was developed and produced as a gas reservoir.
Disposal of Dirty Liquids Using Slurry Fracture Injection
Authors: Dusseault Maurice B. , Bilak Roman A. , Rodwell L. Gene
Published: December 2007

An automated waste liquid injection system for dirty liquids was designed and implemented in an unconsolidated sandstone formation in southeastern Alberta. This development was based on previous waste sand injection in central Alberta. Waste liquids consisting of contaminated water, heavy oil, and fine-grained particulate matter are being diluted and injected under formation fracture pressures. Monitoring for environmental security and process control includes precision tiltmetres and comprehensive pressure analysis. Injectivity, transmissivity, reservoir pressure evolution, and fracture closure pressure calculations based on pressure fall-off and step-rate tests allow the formation state to be continuously re-evaluated. The reservoir is not being impaired by the continued injection of dirty liquids.

This article first describes Slurry Fracture Injection (SFI) history and principles, the site geology, and recompletion strategy. Then, data from the trial period and the summer operations are presented and analyzed. The use of SFI in this new application seems to be highly successful, and the nature of the process and controllable factors are discussed in the context of preserving target formation injectivity.