bluuebunny/crossref_metadata_2025 huggingface dataset:
Hard Rock Drilling Problems Explained by Hard Rock Pressure Plots
Authors: Gill J. A.
Published: December 2007

Hard rock drilling problems are frustrating.

Hard rock pore pressure interpretation is baffling.

Because of slow drilling in hard streaks and absence of kicks (in overpressured shale sections), it is generally assumed pore pressures are close to "normal" over long depth intervals.

Many hard rock drilling problems (Table 1) could not be logically explained, if this were the case.

Nothing could be further from the truth. Hard rocks are difficult to drill because of the extreme zig-zags from overpressured shales to sub-normally pressured sands and carbonates (Fig. 1).

It is impossible to drill anywhere near balanced in both situations, simultaneously. Hard rock drilling problems caused by underbalance or overbalance (or both) are a result (Table 1).

But, a better understanding of the presence and magnitude of these pressure shifts (Fig. 1) will help us minimize the worst extremes of imbalance and more intelligently strike an optimum compromise, realizing that mud density and, especially, mud chemistry can never completely solve these hard rock drilling problems.

Well log pressure plots in these erratic stratigraphies are so difficult to interpret that they often have been considered useless.

The example pore pressure plots shown here, including the Pressure Evaluation Profile (PEP) log – a side by side comparison of several different pressure sensitive responses (Figs. 5, 10) – help interpret and explain many of these problems in a simple, logical manner.
PDC Bits Find Applications in Oklahoma Drilling
Authors: Offenbacher L. A. , McDermaid J. D. , Patterson C. R.
Published: December 2007

Drilling in Oklahoma is difficult by any standards. PDC bits, with proven success drilling soft, homogenous formations common in the North Sea and U.S. Gulf Coast regions, have found some significant "spot" applications in Oklahoma. Applications qualified by bit design and application development over the past two (2) years include slim hole drilling in the deep Anadarko Basin, deviation control in Southern Oklahoma, drilling on mud motors, drilling in oil base mud, drilling cement, sidetracking, coring and some rotary drilling in larger hole sizes.

PDC bits are formation sensitive, and care must be taken in selecting where to run them in Oklahoma. Most of the successful runs have been in water base mud drilling hard shales and soft, unconsolidated sands and lime, although bit life is often extended in oil-base muds,
Summary of API Onshore Drilling Mud and Produced Water Environmental Studies
Authors: Moseley H. R.
Published: December 2007

The restoration/disposal of drilling mud pits and produced water impoundments is a continuously growing concern to the oil and gas exploration/production industry. To ensure proper restoration of of these sites, it is first necessary to determine the environmental effects of drilling muds and produced waters to soils, plants, and surface/ground water. The American Petroleum Institute (API) has sponsored four major studies investigating these impacts to these onshore drilling and production sites.
Optimize Bit Hydraulics for Minimum Cost Drilling
Authors: Doiron H. H. , Deane J. D.
Published: December 2007

In a previous paper, the authors derived a condition for optimum bit hydraulics considering increases in rate of penetration, fuel costs and pump maintenance costs with increased bit hydraulics. This paper is an extension of the previous work and demonstrates practical application of the new hydraulics optimization method. Previously unpublished full scale laboratory drilling data obtained by the authors and test results reported by other authors are presented to demonstrate the relationship of ROP to increased bit hydraulic horsepower. Effects of blanked nozzles and asymmetric nozzle configurations are also presented. Graphical relationships of fuel and pump maintenance cost increases, bit ROP increases and drilling cost variations with increasing standpipe pressure and bit hydraulic horsepower are presented. The optimum condition for bit hydraulics reveals that fuel costs to power mud pumps and pump maintenance costs should be a fixed percentage of total operating costs depending on bit ROP response to increased bit hydraulic horsepower. Recommendations for field application of the optimizing technique are presented.
Bottomhole Pressures Measured While Drilling
Authors: Ramsey M. S. , Robinson L. H. , Miller J. F. , Morrison M. E.
Published: December 2007

Recent in-situ measurements show that major discrepancies exist between accurately measured net bit pressure drop values and those predicted by previously accepted models and equations. The direction of the discrepancies is such that the measured values of net bit pressure drop are 20 per cent lower than those predicted by the existing models. Subsequent laboratory data obtained under rigorously monitored and controlled conditions support the field-taken downhole data. These data, as well as a possible explanation, are presented in this paper.
The Drilling Contract—A Reflection of Market Conditions
Authors: Warren Ted
Published: December 2007

The drilling contract will accurately reflect current market conditions but often at the expense of improperly matching the operator's objectives and the contractors incentives. During a period of rig oversupply, both operators and contractors must avoid using an inappropriate type of contract which may result in loss of drilling efficiency and financial inequities. This paper discusses the factors that should determine whether a well is drilled on daywork, footage or turnkey.
A Strategic Exploration Model
Authors: Warren J. E.
Published: December 2007

Since an estimate of available petroleum resources, and the size distribution associated with them, is a fundamental requirement for the development of a viable exploration program, a theoretical model that simply represents the exploration process has been developed to facilitate the estimation of remaining reserves, the assessment of past exploration performance and the formulation of future exploration strategy. Several commonly employed models have been cited as special cases of this more generalized model and their shortcomings have been indicated. The practical use of this model has been demonstrated with field data and its extension to strategic decision making has been suggested via example; i.e., to obtain an allocation of effort that will achieve specific objectives re expenditures, reserves and risk.
Simulation of a Major Oilfield Gas-Gathering Pipeline System
Authors: Brill James P. , Sifferman Thomas R. , Samaroo Brian , Arirachakaran Srihasak
Published: December 2007

Diameters from 30 to 40 in. (76. 2 to 101.6 cm) were evaluated for two pipelines planned for a gas gathering system in a major offshore oilfield in Saudi Arabia. The dew point gas from separators will undergo retrograde condensation in the pipelines with reduction of pressure and temperature. Calculations required for sizing the pipelines include phase behavior, pressure drop, temperature profiles liquid volumes, flow pattern predictions, liquid flow rates and the minimum gas velocity required to continuously remove liquid from the risers.
Development of a Multiple Application Reservoir Simulator for use on a Vector Computer
Authors: Kendall R. P. , Morrell G. O. , Peaceman D. W. , Silliman W. J. , Watts J. W.
Published: December 2007

This paper describes a new reservoir simulator possessing four distinctive features: (1) It uses a recently developed formulation that is efficient in both black-oil and compositional modeling. (2) It possesses a design that permits it to solve efficiently very large problems on a vector computer while being reasonably efficient on smaller problems and on scalar machines. (3) It uses a novel approach to data management that permits writing most of the program as if it rar in core despite the fact that, in general, data is continually being temporarily stored on and retrieved from disk. (4) Its well management package uses a flexible data structure and logic sequence that permits modeling of complex well and surface facility networks.

The paper presents an overview of the simulator, discussing each of the features mentioned above. It also briefly discusses our experience to date in using the new program and the conclusions we have reached based on this experience.
Application of Rosenbrock Search Technique to Reduce the Drilling Cost of a Well in Bai-Hassan Oil Field
Authors: Aswad Zeiad A. R. , Al-Hadad Saad M. S.
Published: December 2007

The powerfull Rosenbrock search technique, which optimize both the directions of search using Gram-Schmidt procedure and the step size using Fibonacci line search method, has been used to optimize the drilling program of an oil well drilled in BAI-HASSAN oil field, KIRKUK IRAQ, using the two dimensional drilling model of Galle and Woods. This model shows the effect of the two major controlable variables, weight on bit and rotary speed, on the drilling rate while considering the other controllable variables such as; mud properties, hydrostatic pressure, hydraulic design, and bit selection are well chossen. Also the effect of tooth dullness on the drilling rate is considered in this drilling model.

Increasing the weight on bit with a little increase or decrease in rotary speed gave a significant decrease in the drilling cost for most bit run. A 48 % reduction in the total drilling cost and a 97 hours saving in the total drilling time can be obtained by optimizing the drilling program of any well that will be drilled in the same formations using the same types and sizes of bits, the same drilling fluid properties, and the same hydraulics program.

The Rosenbrock search method using Fibonacci line search reached to almost the same optimum drilling cost for most bit runs from different starting points that are far away from the optimum, which shows the ability of this technique to solve and optimize the drilling function given by Galle and Woods.
Primary Cementing Across Massive Lost Circulation Zones
Authors: Turki W. H. , Mackay A. S.
Published: December 2007

As a result of severe lost circulation problems in some wells in the Ghawar and Abqaiq Fields, Aramco has been unable to cover the Umm Er-Radhuma (Paleocene) and Wasia (Cretaceous) aquifers with cement. This has necessitated setting an extended liner opposite the Wasia aquifer, to ensure that there are two casing strings and a cement sheath across the aquifer, resulting in increased casing cost and reduced well productivity.

This paper will describe the results of field trial tests performed, along with conclusions and recommendations aimed at solving this problem.

Field methods employed include light weight extended cements, ultra-light cement slurries weighing as low as 55 lbm/ft3 (pcf), using ceramic hollow spheres, glass bubbles and foam, plus hydrostatic cementing, and mechanical devices.

Finally, methods of job evaluation will be discussed. These include temperature surveys, bond logs, radioactive tracers, and a new cement volume log.
Detection and Remedy of Behind-Casing Communication During Well Completion
Authors: Abdel-Mota'al A. A.
Published: December 2007

Detection and remedy of behind-casing communication is a problem during selective completion of wells on two zones of a multilayered reservoir, where the length of separation between the two zones is critical. This paper presents a new technique - Communication Test-Completion Procedure - which is applied in Abu Dhabi oil fields to overcome this problem.
Improved Oil Saturation Data Using Sponge Core Barrel
Authors: Park Arthur , Devier C. A.
Published: December 2007

Sponge core barrel is proving to be a convenient, economic and acceptable method to obtain improved oil saturation data. Research and development has continued to improve this new tool that is being developed for enhanced recovery operations. The sponge barrel is not only being developed for improved oil saturation but to determine water saturation and CO2 in cores under controlled conditions.
Stimulation Treatment Design and Evaluation of Old Producing Wells
Authors: Sinha B. K. , Elbel J. L.
Published: December 2007

The productivity of many old producing wells can be increased by the use of a properly designed stimulation treatment. The majority of these wells, both pumping and nonpumping, are fractured. Partial healing of the hydraulic fracture may occur as pressure declines in the reservoir. In addition, other common forms of formation damage occur with time. An accurate evaluation of the existing conditions in the well is required for proper design of the stimulation treatment.

In this paper, an attempt has been made to utilize production data and pressure transient test data simultaneously to evaluate the existing condition of the well. The use of published type-curve techniques for unfractured, fractured and decline curve analyses has been emphasized to eliminate ambiguities and to arrive at a reliable conclusion. Both conventional pressure data and liquid-level measurement data have been used in this study. A two-dimensional simulator has also been used to aid stimulation treatment design and performance evaluation.
North Burbank Unit Commercial Scale Polymerflood Project—Osage County, Oklahoma
Authors: Moffitt P. D. , Mitchell J. F.
Published: December 2007

The North Burbank Unit commercial scale polymerflood project began in September, 1980, with the injection of fresh water preflush within a 1440 acre polymerflood project area. Since that time polymer solution at 500 ppm concentration, interrupted by aluminum citrate, and polymer solutions of 2 50 and 50 ppm concentration have been injected. The total polymer to be injected is 4,001,000 pounds of a liquid emulsion polyacrylamide.

This paper deals with operational problems encountered during the project and the response of the project wells to polymer injection. The discussion of operational problems includes shear degradation of the polymer solution, disposal of produced brine, biocide effectiveness, and near wellbore treatments to adjust injection rates into individual injection wells. The response of the project producing wells includes fresh water breakthrough, polymer production, and oil production response to polymerflooding. The discussion of the response of the project injection wells includes injection rate and wellhead pressure histories, and analysis of pressure falloff tests before and during polymer injection.

The project area has responded positively to polymer injection with the production rate from the project area currently averaging 951 barrels of oil per day compared with a pre-project rate of 510 BOPD. The producing water-oil ratio has correspondingly declined frcm a pre-project water-oil ratio of over 100 to a current ratio of less than 50. The interior pattern wells have shown the best response to polymerflooding with the wells on the outside of the project area showing very little response to polymer injection.
Enhanced Oil-Water Separation—The Performax Coalescer
Authors: Rehm S. J. , Shaughnessy R. J.
Published: December 2007

The Freewater Knockout (FWKO) has been the basic oil field standard in oil-water separation for many years; The PerformaxR Matrix Plate Coalescer is an improved enhanced oil-water separator which satisfies the oil producers' desire for a simple, efficient separator. Sizing and case history information is reviewed. Results from light gravity paraffinic oils to heavy gravity asphaltic oils are detailed. The Performax Coalescer with improved oil, gas, and water quality is becoming the new industry standard for oil-water separation.
Stimulation Techniques in the Red Fork Formation in the Anadarko Basin
Authors: Brunette P. T.
Published: December 2007

This paper presents the results of fracture stimulation treatments on the Red Fork formation in the Anadarko basin. All wells studied are located in Roger Mills and Custer counties of Oklahoma (Fig. 14). Only data for which valid production information was available are included.

Fracturing techniques and their results using five different stimulation fluids are examined; cross-linked water base, gelled water (non cross-linked), gelled diesel, gelled carbon dioxide, and foamed carbon dioxide with water as the liquid phase. Three types of propping agents have been used in various grades in conjunction with the above stimulation fluids; sand, intermediate strength proppant and high strength sintered bauxite.

A discussion of various treatment parameters and their possible overall effect on the production results are presented.
Ultra-High Sand Concentration in Hydraulic Fracturing— A Case History
Authors: Shah S. N. , Smith D. R. , Donaldson D. E.
Published: December 2007

Because of their success, ultra-high sand concentration (USC - a commonly used field acronym) treatments have become very popular in Oklahoma. To-date, more than 50 wells have been completed using USC treatments.

This paper presents the state-of-the-art on USC in hydraulic fracturing with field data and documented results. Case histories of the two representative wells selected from different areas of the state, are discussed in detail in the paper. Well production data before and after the USC treatments, are compared. A detailed USC job design procedure is also outlined. Furthermore, some suggestions are made to help the reader in designing and conducting USC treatments.
Improved Well Stimulation With Resin-Coated Proppants
Authors: Sinclair A. R. , Graham J. W. , Sinclair C. P.
Published: December 2007

Resin-coated proppants improve well stimulation results by preventing flowback, or fracture evacuation, near the wellbore, a phenomenon that effectively "decouples" the wellbore and the productive formation. In addition, the deformable coating protects the resin-coated proppants from crushing and helps resist embedment in softer formations. The tough coating is chemically inert in crude oils, brines, and most acids. The resin-coated materials work best under actual down-hole conditions since the closure stress and temperature help lock the materials in the fracture for the 1ife of the well.

This paper reviews case histories from four wells in which resin-coated proppants were used. In addition, simple lab tests of the resin-coated proppants in an API crush cell confirm their excellent properties and potential. Together, these results show the need for resin-coated proppants in many types of wells. In many ways they act as "ideal" proppants that can be economically justified over uncoated proppants.
Production System Optimization for Natural Flowing Water Drive Wells
Authors: Chu M. H. , Evans R. D.
Published: December 2007

This paper presents the results of a computer study which leads to the optimum design of a production system for flowing wells subjected to a natural water drive. The results presented consist of a series of graphs which are derived from an analysis of the inflow performance relationships, vertical lift performance, choke performance, horizontal flow performance, and the thermodynamic conditions of the surface conditioning equipment such as separator and flow lines.

The Hagedorn and Brown correlations and the Beggs and Brill correlations are utilized to determine pressure drop for vertical lift and horizontal flow performance for multiphase flow. Using these correlations and assuming a flow rate and starting from the separator, pressure losses are calculated along the flowline to the wellhead, across the choke, and down the tubing to the tubing intake. Output from the analysis results in an optimized system design which maximizes production for a set of reservoir conditions and surface contraints.

An example well problem are presented which demonstrate the applicability and versatility of the computer analysis. An analysis is also presented to assess the sensitivity of various parameters upon well performance. Such parameters as flowline size, separator temperature and pressure, choke size, tubing size, water oil ratio, gas oil ratio, productivity index, oil gravity and fluid slippage are considered in the sensitivity analysis.

The results of this analysis and the data presented provides the production engineer with a technique for designing a system which will optimize production from a given well. The approach is general in that the outputs from the analysis provides the engineer with a set of curves and graphs to assist in making a final decision concerning a specific well or group of wells.
Steamflooding Strategy for Thin Sands
Authors: Doscher T. M. , El-Arabi M. A.
Published: December 2007

A description is presented of the design of a steam drive in the Chanac sand, which is only 15 to 20 feet in thickness, at a depth of approximately 1250 feet in the Edison Groves field (Kern County, California).
Waste Water Disposal Above Fracture Gradients in California
Authors: Doscher T. M. , El-Arabi M. A.
Published: December 2007

In order to permit economic operation of Placerita Oil Field leases, a request was made of the Division of Oil and Gas of the State of California for a waiver on the regulation limiting the sand face pressure of water disposal operations to a value less than the apparent frac gradient. This is an account of the justification presented to the DOG for seeking a variance from the regulations, the DOG's positive response, and subsequent field operations.
A Laboratory Study of Heavy Oil Recovery with CO2 Injection
Authors: Sankur Vega , Emanuel A. S.
Published: December 2007

Recovery of a California heavy oil by CO2 injection was investigated using laboratory core floods and computer simulation. CO2 drive and huff-n-puff techniques were studied for tertiary recovery of a 14° API gravity, 3000 cp viscosity oil from a waterflooded core. The core material was poorly consolidated sandstone under simulated reservoir stress.

At 1250 psia, CO2 drive recovered up to 54% of the remaining oil in place (ROIP), the recovery increasing with increasing slug size. The CO2 utilization factors also increased with CO2 slug size, ranging from 1.1 MSCF/BBL to 8.0 MSCF/BBL. The addition of 18% N2 into CO2 at this pressure resulted in earlier gas breakthrough and lower recoveries compared to pure CO2 injection.

At 750 psia a 3.0 PV slug of CO2 recovered 20% of the ROIP, reflecting lower recoveries at lower pressures. The use of small slugs improved CO2 utilization also at this pressure with an accompanying decrease in overall recovery to 16% of ROIP.

The CO2 huff-n-puff technique was tested on the same system at 1250 psia pressure. The first cycle recovered 6% of the ROIP with a CO2 utilization factor of 11 MSCF/BBL. The second cycle recovered an additional 3% with a utilization factor of 33 MSCF/BBL.

The core floods were simulated using a compositional simulator with a three-component Peng-Robinson model for fluid properties. The simulator predictions agree qualitatively with the experimental results. Calculated saturation profiles through the core are presented.
Well Completions in the Beta Field, Offshore California
Authors: Bruist E. H. , Jefferis R. G. , Botts T. M.
Published: December 2007

The heavy oil reservoir in the Beta Field, Offshore California is thick (up to 1200 feet gross), unconsolidated, consists of nine distince sand intervals, and lies at a shallow depth. In order to economically develop the field from two platforms and be able to waterflood, the development wells must (1) be highly deviated with an ‘S’ shaped profile, (2) have isolated multi-zone completions designed with the capability to selectively inject or produce any combination of zones, and (3) produce virtually sand-free because of the use of electric submersible pumps for artificial lift.

To meet these requirements, new completion techniques were developed. This paper reviews the overall completion sequence starting with primary cementing and zonal isolation, through perforating and perforation cleanup, and finishing with the inside casing gravel packing and gravel pack logging. The new techniques have proved expedient and successful, with 40 producing wells containing a total of 152 individual zones completed as of December, 1982.
Interference Analysis for Wells Produced at Constant Pressure
Authors: Ehlig-Economides C. A. , Ansari J. A.
Published: December 2007

Although there are numerous techniques for analyzing pressure interference effects for constant rate wells, the analogous rate transients due to interference among constant pressure producers have never been investigated in detail. The transient pressure behavior resulting from interference effects among wells produced at constant rates can be determined in a straightforward manner using the principle of superposition in space. For constant pressure producers, the flow rates are continuously changing. Hence, the pressure interference among constant pressure wells cannot be determined in the conventional way.

In this study, the rate interference among constant pressure production wells is modeled using the diffusivity equation. Pressure distributions in the reservoir for both constant pressure and constant rate couplets were obtained. The two are qualitatively similar and exhibit a similar zone of zero pressure gradient, which confirms the existence of an apparent no-flow boundary between any two constant pressure producers analogous to the one that is known to exist between wells flowing at constant rate. Results also show that a nearby fault boundary can be detected in a drawdown well test as the doubling of the slope of the semi-log straight line produced when the reciprocal of the flow rate is graphed versus the log of time.

Another principal function of modern well testing is to evaluate the formation anisotropies. The method given by Ramey for the constant rate environment does not fully hold for the constant pressure setting. Therefore, a new method for evaluating directional permeabilities has been developed.

To demonstrate the theory in application, example problems have been worked explaining and emphasizing the practical applications of the new techniques.
The Test and Evaluation of a High-Horsepower Cable-Suspended Submersible Pump in a Prudhoe Bay Well
Authors: Drysdale C. E. , Brookbank E. B.
Published: December 2007

A test and evaluation project of the cable suspended pumping system (CSPS) was started in mid-1979 by Sohio to assess a possible alternative method to gas lift in some limited areas of Prudhoe Bay.

The major objectives of the project concerned the applicability of an unproven artificial lift system to a low temperature environment and the high rate, pressure, and GOR of Prudhoe Bay oil wells. The culmination to the conceptual planning was an eight-month field test in Well A-1 during which time three ESP change-outs were performed.

A major result from the field test evaluations concerned cable slippage down through the wellhead cable pack-off. This was attributed to both the cable material response in the large temperature range experienced and the design of the cable retention mechanism.

The hands-on experience provided representative data for state-of-the-art assessment of CSPS. This paper summarizes the technical evaluations of this prototype installation and identifies the work necessary to complete the development for reliable, commercial application in low temperature areas.
The Role of Reservoir Lithology in Design of an Acidization Program: Kuparuk River Formation, North Slope, Alaska
Authors: Boyer R. C. , Wu Chia-Hsin
Published: December 2007

Sandstone lithologies in the Lower Cretaceous Kuparuk River formation were tested to study formation damage during acid treatments. Two lithologies were analyzed before and after acidization: 1) a glauconitic sandstone cemented by siderite, and 2) a sandstone containing clay minerals with minor carbonate cements. These samples were treated with hydrochloric acid containing iron-chelating and silt-suspending agents, with hydrofluoric acid, and with fluoroboric acid, all at reservoir pressure and temperature. Formation damage was evaluated by scanning electron microscopy (SEM), X-ray diffraction, petrographic analyses, and acid effluent analyses. Carbonate cement and clay mineral content were critical factors that governed the extent of formation damage.

Hydrofluoric acid is commonly used to stimulate sandstone reservoirs. However, results showed that this acid caused formation damage in both Kuparuk River lithologies. SEM examination of siderite-cemented sandstones after treatment showed abundant iron-rich and poorly crystalline fines dispersed in pores. These mobile fines included partially dissolved siderite, iron precipitates, and colloidal silica. In sandstones with clays, hydrofluoric acid partially dissolved and released clay particles which could plug pore throats during production. Hydrochloric acid with iron-chelating and silt-suspending agents gave the best results in siderite-cemented sandstones. This acid prevented iron released from siderite and glauconite from forming precipitates and cleaned up the wellbore. Fluoroboric acid was the best treatment in sandstones containing clay minerals. SEM examination showed that this acid cemented undissolved clay particles to framework grains. Thus, pore throats remained open.

Selection of the acid treatment compatible with reservoir lithology will minimize formation damage and lead to increases in production.
Use of Lumped Parameter Modeling for Geothermal Engineering
Authors: Castanier L. M. , Brigham W. E.
Published: December 2007

The theory and algorithm are presented for the implementation of a lumped parameter approach for geothermal reservoir simulation in the early stages of the development of a geothermal field. The model can be applied to all types of geothermal systems: all-liquid, all-steam, or two-phase.

This paper focuses on examples of utilization of a simple lumped parameter model in three cases:

The model is used to verify the validity of experimental results obtained from a bench-scale model and to calculate the heat transfer parameters of the experimental apparatus. In Ref. 1, a brief comparison was made on the East Mesa reservoir between lumped parameter results and the results obtained by Morris and Campbell using a three-dimensional finite differences simulator. We will use this study to show the use of a lumped parameter approach to give focus to the important variables prior to more complex simulation efforts. Production and pressure histories of the Cerro Prieto geothermal field were assembled from field data. The model was then used to perform sensitivity studies on reservoir size, porosity, aquifer recharge rate and temperature of the recharge fluid for the Unit 1 and 2 production area. Two types of depletion schemes were investigated; in the first, the reservoir remains in liquid phase; in the second, the reservoir becomes two phases at an early point of its history. A satisfactory match of the history of the field has been obtained only for the second case.

The problems encountered during the application of the lumped parameter technique to each of these examples are discussed; also, limitations of this approach are mentioned.
Determination of Permafrost Thawing Around Oil Wells
Authors: Sengul M. M. , Brigham W. E.
Published: December 2007

A practical procedure is presented for determining the radius of the thawed-permafrost region around a well and finding the temperature distribution in that region. Such information is important in drilling, completion, and production operations in Arctic regions.

A new numerical method was developed and used in a computer model to generate solutions for radial thawing of permafrost with axial symmetry, which was shown to be a function of three dimensionless parameters plus dimensionless radius and time. The model generated solutions for the range of values of the three parameters for conditions in Alaska's North Slope.

The dimensionless radius of the thawed-permafrost region was related to dimensionless time through a simple power-law equation containing two constants. Results generated by the computer model were used to develop correlations giving the relationships between the two constants and the three parameters. The correlations can be used to find the thawed-permafrost radius, and once this information is available, the temperature distribution in the thawed region can also be calculated.

For the correlations, the temperature at the well was assumed to be constant. In more realistic situations in which well temperature varies with time, we also describe a simple method of calculating the amount of thawing.
Development of High Temperature Electric Submersible Pump
Authors: Pascual Will , Crumley Al , Nelson Chuck , Brady Joseph
Published: December 2007

Todays oil well production is exposing artificial lift equipment to higher and higher downhole operating temperatures as a result of deeper wells and enhanced recovery methods such as steam floods and in situ combustion. KOBE is pursuing a development program that will result in an ESP capable of operation in these high temperature applications. Tests under simulated well conditions of 350°F continuous service are being conducted and have already resulted in design and material developments that make this operation practical. This paper reports on the progress achieved and future testing that is to be done.
Advances in Diver Alternative Systems
Authors: Hawkes G. S.
Published: December 2007

The basic design and selection of oil rig equipment offshore is greatly influenced by the ability to maintain and service such equipment as and when required. A critical analysis of underwater work systems was made and primary research and development conducted that has resulted in advanced new diver alternative systems. Two new systems, a one person one atmosphere microsubmersible, DEEP ROVER, and a robotic device, RIG ROVER, both equipped with newly developed sensory manipulator systems are described. These systems markedly improve work capability subsea and may influence future offshore developments, particularly in deep water.
Interpretation of Some Wireline Logs in Geothermal Fields of the Imperial Valley, California
Authors: Ershaghi Iraj , Abdassah Doddy
Published: December 2007

This study reviews the wireline log responses of some geothermal fields in the Imperial Valley, California. The fields under study include the Heber, the East Mesa, the Brawley and the Westmoreland. The well logs used in the study did not include all the wireline surveys obtained by the operators. The selected well logs obtained under special arrangements with the operators were chosen to maintain the anonymity of specific well locations but are only representative of each area.

Analysis of the well logs indicate that on an individual field basis, the well logs are excellent for correlation purposes. The presence of extremely saline fluids in some fields precludes the monitoring of Qv profile for detection of hydrothermally altered zones. The producing sections in all the fields are characterized by low porosity and high resistivity.
Solid Waste Problems in Geothermal Operations
Authors: Vetter O. J.
Published: December 2007

The solid waste generated in geothermal operations is not limited to silica as often assumed. The silica by itself does not cause unsurmountable solid waste problems. However, numerous other solids coprecipitating with the silica cause major problems in many high temperature liquid-dominated fields.

Depending upon (a) reservoir temperature, (b) reservoir fluid composition, (c) thermodynamics of steam and gas flashing, (d) types of flash and brine treatment facilities and, finally, (e) field operating conditions numerous other solids can be formed at various locations within the field and power plant. Thus, there exists a rather complex relation between the various field parameters and the types and amounts of the various solids.

Solid waste disposal and/or utilization problems are further complicated by the relationships between the formation of scale, i.e., solid deposits adhering to the hardware, and suspended solids to be removed in the various brine treatment facilities prior to reinjection of the heat-depleted brine.

All these complex relationships are explained in this paper by using the rough data from the MCR Mercer 2 field experiments published by DOE/DGE in 1981 and 1982. Approximately 2000 lbs. of a solid, rather impure iron hydroxychloride plus numerous other solid metal compounds are formed from the fluids per well and day.

If these solids are comingled with substantial amounts of amorphous silica, a rather severe waste disposal and/or solid utilization problem becomes evident. At present, this set of problems seems to be the major hurdle for the development of numerous fields.

The technical, economical and environmental problems regarding waste utilization and/or waste disposal are described. Solutions to these problems are far from being available. It is judged that presently developed processes will not solve the rather evident solid waste problems. The only alternative seems to be a combination of mineral recovery and waste disposal processes. This also hampered by numerous technical, economical and environmental problems as shown in the paper.
Analysis of Pressure Pulses Resulting from Magmatic Activity in the Vicinity of Geothermal Wells
Authors: Sigurdsson Omar , Tiab Djebbar
Published: December 2007

The Krafla geothermal field is located in northeastern Iceland. In December 1975 a rifting episode started in the fissure swarm intersecting the geothermal field. Volcanic activity has been associated with the rifting events. During these events pressure pulses have been recorded in nearby wells.

A model based on simple equations describing heat flow in porous media and the pressure diffusivity equation is developed to analyze these pulses. The model is applied to two field cases. The results obtained for transmissivity and formation storage are in good agreement with results obtained from independent well tests.
Rocky Mountain Low Colloidal Oil Mud Applications
Authors: Vesely D. P.
Published: December 2007

Since the advent of low colloidal oil muds in the middle 70s, the system has been tried at several locations in the Rocky Mountains. The system has been used in nearly all basins with mixed results, but in general has proven to be a good choice for deep wells. This paper details the criteria for selecting a low colloidal oil mud over other mud types and documents known areas where the system was successful. In addition, guidelines are presented for estimating cost, along with recommendations for additional equipment and hook-ups required for conserving oil mud.
Fracture Stimulation Treatment of a Western Tight Sand Reservoir: A Case History
Authors: Greenfield H. S. , Ahmed Usman
Published: December 2007

State-of-the-art technology in rock mechanics, fracture mechanics, reservoir engineering and formation evaluation was effectively applied to enhance gas production from a tight gas sand field in Sublette County, Wyoming. Previous attempts at production from this field were not successful due to low initial flow rates and rapid production declines mostly associated with low permeability of the formation. Two research wells were drilled to 12,000 foot depths and a systematic approach towards their completion by hydraulic fracturing was taken by means of associated laboratory, field, and analytic tasks. Laboratory tests on core materials were carried out at appropriate in-situ conditions which resulted in the use of suitable fracturing fluids that caused minimum damage to the matrix permeability and fracture conductivity. Water-base fracturing fluids with high pH (≃8.0) values were recommended for the sand zones investigated. In-situ stress measurements were also taken in and around the selected pay zones. Proper and cost effective proppants were used and strict quality control procedures were imposed during the stimulations.

One zone in each well was successfully fractured. Prestimulation initial production of 107 MCFD for the first well was increased to a post-stimulation value of 4,150 MCFD while the second well was increased from 35 MCFD to 1,450 MCFD. Long-term deliverability projections were made by history matching post-stimulation production and build-up test data.

Presently, the obtaining of ten months of continuous production data from the two research wells is ongoing. A unique trucking procedure to transport the produced gas to a somewhat distant transmission line is emphasized in this case history discussion.
Use of Continuous Coil Tubing for Subsurface Scale and Corrosion Treating—Rangely Weber Sand Unit
Authors: Cruise D. S. , Davis D. L. , Elliott R. H.
Published: December 2007

The deposition of calcium carbonate and/or barium sulfate scale on submersible pumps is the most serious production problem in the Rangely Weber Sand Unit. The conventional method of flushing scale and corrosion inhibitors continuously down the annulus is effective from the pump intake up, but offers no protection to the seal and motor. In an effort to protect the entire pump assembly, Chevron U.S.A. Inc. (CUSA) banded a string of 3/4″ continuous coil tubing to the outside of the production tubing along with the power cable so that chemicals could be injected below the pump. The original installation was a success, and at present there are approximately 30 such installations in Rangely.
Troubleshooting Mature Waterfloods
Authors: Robinson K
Published: December 2007

There has been quite a number of informative papers published recently describing seawater-injection facilities for fields such as B.P.'s Forties (Ref. 1) and Chevron's Ninian (Ref. 2) in the North Sea and GUPCO's El Morgan in the Gulf of Suez (Ref. 3). Those waterfloods described were for relatively new developments, with reservoir permeabilities varying from 100-2,000 millidarcies. They are generally recognised as being successful floods, although each author notes various operating problems caused, for example by corrosion, scale formation and bacterial fouling.

This paper attempts to provide a logical approach to identifying the essential causes of operating problems encountered in a waterflood. These problems can have a dramatic effect on the economics of oil production, particularly for older floods and with tighter formations, where permeabilities may be around 1‒10 millidarcies or less.

Before discussing troubleshooting specifically, consideration is first given to the effects which lead to recognition that there is an operating problem. Waterfloods which use seawater tend to be most common, and have the highest flowrate. However, the following comments are just as appropriate to waterfloods using produced, aquifer or fresh surface waters. The problems may be classified into five groups
Choice and Application of Motion Compensation Systems (MCS)
Authors: Manesse J P
Published: December 2007

DEFINITION OF AN MCS

We will define the MCS in the following way:

System allowing:

– either to transfer a load – or to maintain a connection

between a fixed-support (bottom-supported unit) and a floating support.

This definition can also be extended to immobilisation into space (generally sea water) of a load suspended to a floating support.

We will remind you also of the difference between active and passive systems, due to the fact that it is an essential difference for MCS.

– a system is called passive when it is submitted to external actions and its reactions are only a function of its own characteristics. – an active system receives energy in order to counterbalance external actions. A data-acquisition system of the relative movements floating support/fixed support must be provided.

CHOICE OF MCS

Selection Chart

We have designed a selection chart for MCS clients (see Fig. 1). To be effective, it is very important that the problem be well described and understood.

Solutions for an MCS problem must be adapted since a universal solution does not exist.

The selection chart is composed of different levels to be crossed step by step:

– relative position of the handler and the handled – required function – different technical selection criteria allowing a first approach of the chosen active/passive system. (These criteria are information guide-lines only.) – handling system of the load on the handler – technical solution that we illustrate by a sketch or a reference to an existing leaflet, (see Fig. 2 – Design of solutions)
A North Sea Template Well Tieback System: Design and Operational Experience
Authors: Ingram G W , Humphrey B
Published: December 2007

The North West Hutton field is located in Block 211/27 of the UK sector of the North Sea. It is 80 miles north east of the Shetland Islands, in 473' of water. The field was discovered in 1974. Amoco (U.K.) Exploration Company is operator on behalf of British Gas North Sea Oil Holdings Limited, Amerada Petroleum Corporation of the United Kingdom Limited, Texas Eastern North Sea Inc. and Mobil North Sea Oil Limited.

Development of the field began in 1979 with the installation of a subsea template to allow subsequent early production. The 20-slot template was of unitised construction and was installed and piled in place from the semi-submersible drilling rig Dixilyn Field 96. The DF 96 subsequently drilled seven development wells over a 20-month period and also set bumper piles adjacent to the template. The 60" bumper piles were used to locate the jacket over the template when it was installed in September 1982 followed by hookup and commissioning, tieback and completion of the development wells and first oil in April 1983.

The platform has 40 well slots on an 8 × 5 pattern. It supports two drilling rigs, each serving a 20-slot wellhead bay. Priority was given to the completion and commissioning of the east rig, which covers the 20 slots of the platform which are matched to those of the template. Tieback operations and some completion work were then carried out in advance of production-train commissioning. Accordingly, three wells had been completed and were awaiting perforation on 1 April, 1983, when the platform was certified for production. When all seven are completed the tieback wells should be able to supply the platform's design production rate of 100,000 bopd.
The Petroleum Engineer's Professional Responsibility
Authors: Hickman T. Scott , Mistrot G. A. , Wines G. Bing
Published: December 2007

Because a majority of petroleum engineers fall under the industrial exemption, registration is usually taken for granted as a procedure that is always available if needed. Even registered engineers in public practice tend to view it as a governmental requirement without relating registration to their status as a professional and their responsibility to the public's health, safety and welfare. Professional registration is not exempt from the winds of change originating in our increasingly consumer-oriented, environmenţly-conscious society. Although petroleum engineering has been a well established discipline for over fifty years, it is classified as a "minor" discipline because of the number of licensed practitioners. The increase in the number of recognized minor engineering disciplines in the last two decades has led to proposed revisions in the registering process. Lacking a well developed professional image, petroleum engineering is vulnerable to these proposed changes. Recently, two states proposed revisions that would make it more difficult to register as a petroleum engineer. Periodically, industrial exemptions come under question. These are few of the current issues that pose a possible threat to registering as a petroleum engineer.

The practice of engineering is not a natural or constitutional right. The separate states have the authority to determine who is qualified to practice as an engineer. If the majority of petroleum engineers are content to earn a paycheck and achieve passable competency in a limited area with little regard for the broader aspects of professionalism, we may lack sufficient credibility as a discipline to control our destiny.