bluuebunny/crossref_metadata_2025 huggingface dataset:
Effective Limits of Concentration the Reverse Osmosis Process
Authors: Johnson James S. , McCutchan Joseph W.
Published: December 2007

1967 SPE Annual Fall Meeting, Houston, October, 1967

An experimental program utilizing the Coalinga, California reverse osmosis pilot plant was undertaken to determine the effective maximum degree to which the brine could be concentrated. The effect of precipitate formation on the semipermeable membranes was also determined.

The tests were divided into essentially three phases:

the feed brine was acidified to determine the effect on the system of pH adjustment, with the pH of the feed brine adjusted by acid injection to control alkaline scale formation, the feed flowrate was lowered until scale formed in the system, and step two was repeated using reduced flowrate without pH adjustment.

The preliminary brine acidification resulted in a 53% increase in the flux of the 112 tubular membranes already in use in the plant while the flux of the new membranes which had just been installed was not effected. Simultaneously, a decrease of 29% - 48% in desalination ratio was observed for all membranes, new and old. These effects were attributed to the removal of particulate matter from the membrane surfaces.
Oil/Water Gravity Drainage Mechanisms in Oil-Wet Fractured Reservoirs
Authors: Hamon G.
Published: December 2007

When oil-wet fractured fields are produced by natural water-drive, the ultimate oil recoveryof the block depends on the final balance between the capillary and gravity forces. Therefore to get reliable performance predictions with dual-porosity simulators, an accurate determination of the capillary pressure curve is needed. Oil-water gravity segregation mechanisms were investigated, by performing wettability tests, waterfloods and long-term gravity segregation experiments on field samples with live fluids.

Experimental and numerical results indicate that the oil recovery by water gravity drainage can be significant (depending on the matrix permeability). However when assuming no capillary continuity between blocks in a moderately fractured reservoir, the numerical predictionof the gravity segregation efficiency is very sensitive to the capillary pressure input inthe very low pressure range (less than -0.5 psia). An alternative method is proposed to accurately determine in reservoir conditions the crude oil-brine capillary pressure curve. It consists of matching by numerical simulation the transient production and differential pressure of an ultra-low rate waterflood, followed by floods at increasing rates. The reliability of this approach has been checked by simulating correctly some laboratory gravity drainage experiments.
The Use of Bottomhole Temperature Variations in Production Testings
Authors: Jones C.
Published: December 2007

Temperature data recorded during production testing have been interpreted and the results found to be a useful source of information to supplement the pressure data. Increases in bottom hole temperature while flowing are explained by the Joule-Thomson inversion effect. During shut-in periods, the temperature declines and it has been found that the fall-off can be analysed using transient well test analysis techniques. Three field examples are presented where effects attributed to reservoir geometry yielded similar responses on both the pressure and the temperature analyses. A fourth example demonstrates how the analysis wrongly interpreted variations in temperature for no-flow boundaries. This paper shows how the variations in temperature during the shut-in behaves in a similar manner to the transient pressure behaviour in a wellbore. A procedure for estimating the static reservoir temperature is also recommended.
Improving the Performance of Parallel (and Serial) Reservoir Simulators
Authors: Barua J. , Horne R. N.
Published: December 2007

Parallel computers hold much promise for scientific computation. So a great deal of effort has been devoted to finding ways to parallelize linear equation solvers.

However in fully implicit reservoir simulators the real problem is the solution of non-linear equations. This paper shows how a judicious combination of linear and non-linear solution techniques can lead to the fastest overall simulator. It uses a combination of an approximate iterative solution of the Jacobian and a Quasi-Newton method.

The proposed method makes it possible to use the highly parallelizable Jacobi matrix solution techniques, which are poorly convergent, and still get good serial performance.

Experiments on a parallel computer show that even with a highly parallel method, problem sizes need to be quite large to get good efficiency.

The proposed method can also be used to speed up serial programs by simply using a good serial technique to iteratively solve the linear equations.
Multigrid Methods for Three-Dimensional Petroleum Reservoir Simulation
Authors: Dendy J. E. , McCormick S. F. , Ruge J. W. , Russell T. F. , Schaffer S.
Published: December 2007

The purpose of this paper is to report on a preliminary study of a new multigrid scheme for solving three-dimensional problems of the type that arise from pressure equations in reservoir simulation. The basic idea of this new approach is to use both semi-coarsening and plane relaxation in order to accommodate all types of anisotropies and heterogeneities. The scheme also simplifies and reduces the cost of the setup involved in automatic coarsening of the fine-grid equations.

This paper presents the results of the new approach applied to several known test problems. A comparison of performance and complexity is made with the best solvers now in widespread use in reservoir simulation.
Improved Stability of the IMPES Formulation for Chemical Flooding
Authors: Foulser R. W. S. , Goodyear S. G.
Published: December 2007

IMPES formulations of reservoir simulation equations solve for the pressure implicitly using time lagged mobility functions and subsequently update the concentrations explicitly. The Courant stability criterion for the explicit step is well known; however a new source of instability has been identified in the pressure equation when the mobility terms contain a pressure dependence which is time lagged. This can arise from shear dependent viscosities in polymer flooding or from the capillary number dependence of relative permeabilities in surfactant flooding. A stability criterion is derived for one dimensional problems and demonstration calculations for surfactant flooding are used to illustrate its application. If the criterion is violated stability cannot be restored by reducing the timestep.

Two new formulations of the pressure equation are derived to eliminate the instability and are implemented in one dimension using a modified Newton scheme implicit in the capillary number. One of these formulations uses an improved numerical representation of the capillary number and mobility terms, and is preferred because it reduces numerical dispersion and the solution time in the new pressure solver.

The new methods are generalised to two and three dimensions. This involves the introduction of more terms into the pressure matrix which is now non-symmetric. However to leading order the new representation of capillary number leaves the bandwidth the same as the conventional IMPES method, thus limiting the cost penalty of the improved scheme.
Automation in Drilling
Authors: Bromell R.J.
Published: December 2007

American Institute of Mining, Metallurgical and Petroleum Engineers, Inc.

This paper was prepared for the 42nd Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Houston, Tex., Oct. 1–4, 1967. 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.

Application of a "systems concept" to the drilling operation is discussed in this paper. Through the use of hydraulics, electrical systems, electronics and a new approach in basic design, automation of oilwell drilling has been accomplished. The basic functions of the machine are described and methods of control are presented in simplified form.

Automation will permit an increase in the application of engineering to drilling operations through the use of computer control. Downhole variables can be adjusted for optimum drilling rates; safety features can be incorporated in the controls to minimize downhole hazards while tripping; and vast amounts of data can be accumulated since all machine functions are continually monitored electrically.

Rig safety should be greatly improved due to the remote operating position of the crew.

It is concluded, that through automation, economics of oilwell drilling will improve due to lower moving costs, improved safety, increased efficiency and better working conditions which will upgrade personnel.

Introduction

Any repetitive operation, such as the making and breaking of drill string connections when tripping or adding joints of pipe when drilling, lends itself to automation. Economics within the drilling industry have prevented, until now, the development of an automatic machine to perform drilling functions. Domestic land drilling has seen the exodus of most of its qualified personnel to offshore, foreign drilling and more desirable industries with better working conditions. Cheap equipment through cannibalization and auctions, has helped the remaining contractors to stay in business with no earnings from which to modernize. While replenishing their rigs from the vast reservoirs of used equipment they could not correct the economic pressures brought about by reduced demand. These same pressures forced personnel from the industry.

While the land contractors were retrenching, foreign and offshore drilling experienced a record growth.
Implicit Compositional Simulation of Single-Porosity and Dual-Porosity Reservoirs
Authors: Coats K. H.
Published: December 2007

This paper describes an implicit numerical model for compositional simulation of single-porosity and dualporosity oil or gas condensate reservoirs. A 3-component equation-of-state compositional approach is proposed as a desirable alternative to extended black oil modelling, requiring little more computing time than the latter. The approach is illustrated for an actual near-critical volatile oil reservoir. A simple method for reducing implicit formulation time truncation error is described and illustrated. A new bottomhole constraint function is described for better preservation of production well target rates in compositional models. A new matrix-fracture transfer formulation including matrix-fracture diffusion is presented for the dual-porosity description; its accuracy is examined in connection with several test problems where correct results are available from single-porosity simulation. Results are discussed for a 3D 600-block simulation of a highly fractured near-critical volatile oil reservoir.
Natural Fracture Distribution in Reservoirs Modeled by Backstripping and Finite Element Stress Analysis
Authors: Jensen O. K. , Bresling S. , Christensen O. W. , Rasmussen F. O. , Foged N. , Petersen K.
Published: December 2007

A deterministic model is described which enables the stress conditions to be calculated based on the structural growth history. The method provides a framework for estimating natural fracture distribution and directions. The method is developed for two dimensional cross sections and can be extended to three dimensions.

A depth converted seismic profile is used for dividing the geological section into a finite number of time defined formations. The individual formations can be intersected by fault traces. The paleo-appearance of the cross section is constructed through steps in geological time by stripping off formations from the top. In each step the remaining section is decompacted under the decreased load based on the compaction trend of the individual formations. For structural restoration, unfolding and movement along fault traces are made. During this backstripping the displacements are recorded for the subsequent stress analysis.

Stresses are calculated by finite element modelling. An elastic/plastic strain hardening model is proposed. It includes a time dependent creep model making it possible to predict formation properties through geological time. An elastic/plastic finite element model has been designed to calculate stresses by use of these displacements.

The results of the stress analysis are predictions of the stress state being either elastic or plastic: compaction, compressible shear or tension fracture orientations is given too for each point in the reservoir at the steps in geologic time. The level of stress can be "history matched" with well data, well test analysis, fracture identification logs, in situ stress measurements etc..

Illustration of the method is presented for two oil bearing chalk reservoirs overlying salt diapirs in the North Sea. One example illustrates the stress state in a heavily fractured reservoir and the other, a less fractured reservoir.
Estimating In-Situ Permeabilities for Reservoir Simulation Using Multi-Variable Transforms: Two Case Studies
Authors: Carr B. S. , Metcalfe S. L. , Saleri N. G.
Published: December 2007

This paper describes two case studies which illustrate the development and practical application of multi-variable permeability transforms in reservoir simulation studies. The complex lithologies of the two reservoirs under study and the apparent lack of adequate correlations between porosity and permeability necessitated the use of multi-variable transforms. The described methods proved instrumental in the permeability characterization of the reservoirs and in the construction and history-matching of the respective simulation models. In essence, the methods were based on the integration of reservoir information from well logs and cores, subsequently calibrated against well tests.
A Method for Modelling Incomplete Mixing in Compositional Simulation of Unstable Displacements
Authors: Nghiem L. X. , Li Y. -K. , Agarwal R. K.
Published: December 2007

A major deficiency of current compositional simulators is their failure to model the effect of unstable displacements caused by adverse mobility ratios. Since the injected gas is less viscous than the oil, the gas front becomes unstable and numerous fingers develop and penetrate the oil giving rise to poor displacement and sweep efficiency. This shortcoming restricts the application of current compositional simulators, and engineers often opt for a pseudo-miscible black-oil simulator to model unstable gas displacements. This is certainly unfortunate because a pseudo-miscible simulator does not have all the phase-behavior mechanisms of a compositional simulator.

This paper presents a novel approach for modelling unstable displacements in a fully compositional model. The method distinguishes two flow regions in each reservoir gridblock:

a region where complete mixing occurs between the oil in place and the injected gas. a bypassed region where the oil is not contacted by the gas but can still flow because of pressure gradient.

Transfer of components is allowed between the bypassed region and the completely mixed region to simulate the phenomena occurring at the edges of the fingers. The bypassed region shrinks as components are transferred into the mixed region. A two-parameter model is developed to model the transfer rate. Equation-of-state flash calculations are performed in the mixed regions for accurate predictions of phase behavior.

The method is tested against data showing:

Unstable miscible displacement in one dimension. Unstable miscible displacement in two dimensions. Interaction between phase behavior and fingering effect in a near-miscible gas injection process.

Comparisons with a compositional model without fingering effect are also presented.
An Anistropic Coarse-Grid Dispersion Model of Heterogeneity and Viscous Fingering in Five-Spot Miscible Displacement That Matches Experiments and Fine-Grid Simulations
Authors: Ewing R. E. , Russell T. F. , Young L. C.
Published: December 2007

Our objective is improved understanding of how to model the effects of heterogeneity and viscous fingering in adverse-mobility-ratio miscible displacements. We hypothesize that a formulation along the lines of Young, modified to allow for distinct longitudinal and transverse dispersivities, can use coarse-grid dispersion relationships to represent averaged fine-scale behavior. To study this question, we perform numerical simulations in five-spot geometries, using accurate finite-element methods on very fine grids, and attempt to match the resulting recoveries with coarse simulations employing an appropriate anisotropic dispersion term. We also compare the coarse-grid and fine-grid simulations to published experimental data.

It turns out to be very difficult to analyze the effects of the parameters in Young's model, due to statistical uncertainties in oil recovery. Different realizations of the same statistical properties of permeability can yield very different results. This raises many questions that should be studied further.

Despite the uncertainties, some clear conclusions can be drawn from our data. The anisotropic coarse-grid dispersion model can match experiments and averages of fine-grid realizations very well, while the traditional mixing-parameter model of fingering overestimates sweep efficiency and underestimates displacement efficiency when a comparable grid is used. Anisotropy is important, because it reduces recovery and avoids the optimistic predictions often attributed to convective-dispersion models. At the levels of heterogeneity considered in this study, with one standard deviation of a log-normal distribution representing a permeability increment of up to 50 percent, heterogeneity by itself does not influence recovery as much as fingering does.
New Downhole Filming Amine Corrosion Inhibitor for Sweet and Sour Production
Authors: Papir Y. S. , Schroeder A. H. , Stone P. J.
Published: December 2007

A new oil-soluble, filming amine corrosion inhibitor has been developed specifically to treat both sweet and sour corrosion in downhole applications. Its structure contains no amide groups and, thus, is more chemically and thermally stable than the amidoamine and imidazoline-based products widely used in downhole corrosion treating.

The new inhibitor has been evaluated both in the laboratory using wheel test screening methods and in the field. The field trial comprised an entire battery of 39 sour producers at the McElroy Field near Crane, Texas, and was conducted over a 14-month period. Laboratory data indicate superior film persistence of formulations of the new amine at lower concentrations, longer times, and higher temperatures than a commercial corrosion inhibitor currently in wide use throughout the Permian Basin and elsewhere. The average batterywide corrosion rate decreased from 2.5 mpy for the commercial inhibitor to 1.6 mpy for the Chevron Amine-based product. In addition, electrochemical Pair probe measurements on batch-treated wells clearly show the improved film persistence of the new material.
A New Method for Studying Phase Behavior of Enhanced Oil Recovery Surfactant Systems
Authors: Smith D. H. , Covatch G. L.
Published: December 2007

The use of isoperibol calorimetry to obtain phase boundaries and compositions for two-phase amphiphile/water systems and three phase surfactant/oil/water/systems is demonstrated. Because the phase data are obtained without waiting for emulsions to break, the calorimetric technique is much faster than conventional methods. Furthermore, the technique yields heats of mixing (excess enthalpies), which are needed for the development of equations-of-state and the prediction of phase behavior. Because the samples studied need not transmit light, the calorimetric technique eventually may prove very useful for the study of surfactant/CO2/oil/water miscible-flood mobility control systems and systems that contain black oil.
A Practical and Comprehensive Well Logging Evaluation Technique for Modern Computers
Authors: Alcocer C. F. , Hayatdavoudi A.
Published: December 2007

Since successful crude oil recovery is dependent on knowledge of reservoir parameters, accurate and quick evaluation of well logs is important. Consequently, a computer technique has been designed and prepared to assist engineers in well logging evaluation tasks.

The technique presented in this paper is a well Logging package written in Fortran 77 to perform well log evaluation. The overall flow of the system is: Data entry; review and editing; selection of calculations; output of results in either tabular or plotted form. The output is valuable because interpretation from either the table or the plot is faster and more accurate than interpretation from a suite of raw logs. The technique is comprehensive to perform all the fundamental typical well logging calculations. It scans several traditional combinations of well logging programs that are usually run for the evaluation of hydrocarbon wells.

This version of the package or computer system is practical to implement in a main frame computer and has been used for instructional purpose in the USL Petroleum Engineering Department.

This version is expandable by adding routines. Little, if any, rewriting will be needed. More effort is needed to produce a package which is usable without a training session. Currently a significant time, minimum 2 hours, is needed to familiarize the user with the package operation. The system is designed to perform calculation of shale volume, true formation resistivity, porosity for single and dual matrices, and fluid saturations of the flushed and virgin zones. By using a residual oil saturation and movable oil an overlay plot can be produced to visualize the average distribution of fluids and solids in the reservoir. Results yield by the package are reasonable in agreement with those results generated by commercial packages with the same objective.
CO2 Mobility Control Carbonate Precipitation: Experimental Study
Authors: Puon P. S. , Ameri S. , Aminian K. , Durham D. L. , Wasson J. A. , Watts R. J.
Published: December 2007

One of the major problems associated with BOR in general and with CO2 flooding in particular is the tendency of the displacing fluids to bypass most of the crude oil in the flood pattern. The high mobility CO2 seeks out the path of least resistance through the largest pore openings and takes the most direct route between the injection well and the production well. Mobility control is, therefore, an important problem in CO2 flooding. Several methods have been used in an attempt to alleviate the situation, but none have been successful to a satisfactory degree. One way to overcome the tendency of CO2 to bypass the residual oil would be to plug the large pores by forming solid materials in the individual pore spaces through in situ chemical precipitation. Several relatively inexpensive salts of the alkali earth group that are soluble in water react with CO2 to form solid carbonates that can plug the pores. Once the precipitate is formed in the large pores, subsequent fluid flow will be forced to take place through alternate pore paths, thus, increasing the ultimate recovery. The overall objective of this study has been to evaluate the technical feasibility of utilizing carbonate precipitation for mobility control in CO2 flooding. The preliminary experimental work indicated that the carbonate precipitation can occur under various reservoir pressures and temperatures when the pH ranges between 7 to 8. Berea sandstone core samples have been utilized to study the effects of carbonate precipitation relative to altering/reducing permeability under a variety of pressures and temperatures. The results indicate that the permeability can be significantly reduced by in situ carbonate precipitation. In order to further investigate the nature and extent of precipitation propagation in the core samples, a number of experiments have been conducted in pairs of cores connected in parallel and series. The results indicate that the carbonate precipitation is not localized in the core samples and the permeability profile can be altered successfully. Further relative permeability experiments verify the effects of the carbonate precipitates on the flow behavior of the cores.
The Use of Convolution Type Curves for the Analysis of Drawdown and Buildup Tests
Authors: Ayestaran L. , Minhas H. N. , Kuchuk F. J.
Published: December 2007

One of the most important objectives of transient well-test interpretation is to recognize the well-reservoir system (identification) that is being tested, before estimating its parameters such as permeability, skin, and reservoir pressure. This paper presents a procedure for system identification and parameter estimation for single layered reservoirs using downhole pressure and flow rate measurements. However, the procedure can also be applied to commingled reservoirs if each zone is tested in accordance with the multilayer testing technique. The procedure consists of three steps. The first is a system and flow regimes identification (diagnostic) from deconvolution, and specific convolutions and their derivatives. The second step is to obtain all possible parameters and to refine the model further from flow regime analyses and type curve matching using the rate normalized pressure and its derivatives with a few selected models. Any parameter estimated from the flow regime analyses is used as initial guesses for type curve matching. The final step is the verification that allows an automatic estimation of parameters using the most probable model. At the final step, the selected model should satisfy all observed transient measurements and the past production history as well as geological and well log information.

The procedure for transient well test interpretation presented in this paper demonstrates the advantages of using downhole flow rate and pressure measurements. In addition, the paper explores the use of the Gladfelter deconvolution of pressure and flow rate data for model identification. The convolution type curves (CTC) are presented. The interpretation procedure was successfully applied to a field well test example.
Applications of the Net Present Value (NPV) in the Optimization of Hydraulic Fractures
Authors: Balen R. Mark , Meng H-Z. , Economides Michael J.
Published: December 2007

The concept of the net present value (NPV) has been introduced as a systematic approach in the optimization of hydraulic fractures. The scheme combines reservoir and well performance, rock mechanics principles, fracture propagation models, fracturing fluid rheology, proppant transport, and stimulation treatment variables. The method involves the graphing of a range of fracture lengths (or other treatment variables) against the NPV. The optimum length corresponds to the maximum NPV.

Two field cases (one for an oil and another for a gas well) are used for fracture treatment optimizations. Studies for each well show the impact of parameter variation, including the choice of proppant, fracturing fluid, pump rate, treatment pressure (controlled by tubular selection), and volumes of fluid and proppant injected. Variables affecting fractured well performance are also examined, e.g., tubing size and wellhead or bottomhole flowing pressure. The optimization technique also shows the cost of uncertainty and the importance to know—before the treatment—the reservoir permeability, height, and porosity. In particular, an order of magnitude variation in the permeability results in a substantial difference in the optimum fracture length (several hundred feet) and the implied maximum NPV. A study on the effect of the closure stress on proppant performance and the resulting NPV ratio also is included.

This systematic approach to hydraulic fracture design is an important tool in the identification of the crucial parameters affecting a particular job, and allows their control before and during the treatment.
Effects of Stimulation/Completion Practices on Eastern Devonian Shale Well Productivity
Authors: Nearing T. R. , Startzman R. A.
Published: December 2007

A variety of completion and stimulation practices have been used in Eastern Devonian Shale wells during the more than 60 years since its initial development. Over 1000 wells in thirty-four counties located in the west central part of the Appalachian basin, were analyzed to investigate the effects of these practices on well productivity. This study represents the largest investigation to date of post-treatment response using a reliable indicator of the well's long-term deliverability for comparing both explosive and hydraulic fracturing methods.

The traditional measure of well productivity, initial open flow, gives a poor indication of the well's long-term potential. The cause of this poor relationship can be partially attributed to the insufficient test times run during open flow measurements. A more representative indicator of long-term potential, available early in the well's life, has been identified.

Based on location data from wells in the study area, field development of the Devonian shale has been associated with existing localized fold/fault systems. Drilling activity appears to concentrate around structures created as a result of major basement tectonic activity.

The purpose of this study was to isolate the effects of stimulation practices from the background effects of geology and differential reservoir depletion rates. By recognizing these sources of variability, comparison of well productivity for the various stimulation practices was made using standard statistical inference techniques.

The results of this study indicate that larger stimulation treatments, either by explosive shooting or hydraulic fracturing, have not generated incremental improvements in well productivity on a regular basis. A group of post-1975 wells were analyzed to limit the time dependant effects of reservoir depletion. Results from this group indicated natural completions, at a statistically significant level, exhibited greater productivity as compared to that of nitrogen fractured or shot wells. In evaluating the more modern practice of hydraulic fracturing, the foam fractured wells exhibited significantly greater productivity than comparable wells stimulated by explosive shooting.
Field Measurements of Dynamic Pressure and Seismic Activity During Foam Fracturing
Authors: Locke C. D. , Overbey W. K. , Yost A. B.
Published: December 2007

Results of a highly-instrumented multiple-well field test to measure pressure responses during hydraulic stimulation of a naturally-fractured gas reservoir are presented. The field test consisted of a 70,000 gallon (265 m3) "foam frac" in one of four test wells while monitoring bottomhole pressures in each of the four wells and monitoring the site with an array of tiltmeters. A 75-quality sand-laden foam was injected into the naturally fractured formation at a rate of 20 bbl/min (3.2 m3/min). The injection rate was held nearly constant except for two brief interruptions. Sand concentration during the treatment ranged from zero to two and one-half pounds per gallon while average one pound per gallon. Bottomhole pressures were monitored in the fraced well and in three observation wells. Tiltmeters were installed at 12 surface locations encircling the stimulated well at distances of approximately 600 to 1000 feet (180 to 300 meters) to aid in determining the geometry of the induced fracture.

The tiltmeter and pressure responses were analyzed in conjunction with pre- and post-stimulation interference tests to obtain fracture geometry. Eight of the twelve tiltmeters gave clear and analyzable responses. Application of computer codes to the field data provided estimates of fracture geometry caused by the treatment. Bottomhole pressure responses at the three offset wells ranged from 15 to 40 psi (100 to 275 kPa), and occurred gradually over a period of several hours with occasional rapid increases to 1 to 2 psi (7 to 14 kPa) within a 15-second interval.
Centrifuge Measurements of Capillary Pressure: Part 2 – Cavitation
Authors: Hirasaki G. J. , O'Meara D. J. , Rohan J. A.
Published: December 2007

Centrifuge air/water capillary pressure measurements made at one atmosphere ambient pressure can have the liquid in tension (negative absolute pressure) and cavitation of the liquid is suspect. Theoretical arguments show that cavitation in the liquid saturated region should not occur with water-wet rocks having capillary entry pressure less than three atmospheres. Thermodynamics argue that water that is in hydrostatic equilibrium in the pore space that has been invaded by a gas that is also in hydrostatic equilibrium can be in chemical equilibrium with the water vapor in the gas. An experiment showed no evidence of cavitation in rocks with a capillary entry pressure of 50 psi.
Case History: The Design and Construction of Earthquake-Resistant Platform Drilling Rigs
Authors: Cardenas J. L. , Fetterly W. D. , Fowler J. R.
Published: December 2007

Offshore platform rigs that can survive a potential earthquake are currently being designed and built by utilizing computer analysis. The rigs are modeled using finite element analysis and analyzed using the dynamic response spectrum method. By following this approach the rigs can be operated safely in earthquakeprone areas such as California and Alaska.
Oil Muds in Large-Diameter, Highly Deviated Wells: Solving the Cuttings Removal Problem
Authors: Seeberger M. H. , Matlock R. W. , Hanson P. M.
Published: December 2007

An investigation of hole cleaning in large diameter, high angle holes by oil-base muds is summarized. The rheological requirements which must be met to achieve efficient cuttings removal will be discussed. Laboratory and field results using an additive which helps oil-base muds meet these requirements are described.
Forecast and Review: Offshore Rig Activity
Authors: Lawrence S. D. , Gabrielsen G.
Published: December 2007

Forecasting market trends or developments, with a reasonable degree of accuracy, has never been easy. The billions of dollars in offshore drilling assets and/or debt that have been written down are a testament to the difficulty in developing an accurate forecast.

Forecasts are difficult because the individual(s) preparing a forecast must: (1) assemble and analyze data, (2) determine what data is relevant, (3) identify trends or market developments, and, (4) develop an understanding of the often complex interrelationships normally found in an industry. All this to be done before developing at a forecast.

In this paper, an Econometric Model, developed during the past eight years, will be reviewed.

The Model is primarily based on: (1) explicit quantitative descriptions of how the offshore rig market has performed since 1972, and (2) energy prices. In this paper, key factors which influence offshore rig demand, supply, active utilization and dayrates will be reviewed. And, specific Projections for 1989 will be presented, with accompanying graphs, based on the Econometric Model and potential values, or outcomes, for the industry's key factors
Drilling Decisions in Periods of Oil and Gas Price Volatility
Authors: Kerridge I. C.
Published: December 2007

Most drilling decisions, after weighing the geological prospects, are made with the help of a rate of return on investment calculation. Critical to the results are oil and/or gas price assumptions, although they are of diminishing importance over the period covered in the calculation.

Price volatility in the recent past not only makes price assumptions more difficult, it can prompt inaction on prospects offering an adequate return. While not suggesting that oil or gas prices can be predicted or that traditional analysis should be abandoned, this paper suggests some factors (often non-quantifiable) that should be considered in making the decision whether or not to drill.

Some of these factors include: Finding cost differentials.Political risk."Sunk costs."Reserves trend of firm or producer.Auto correlation of future prices and costs.Firm or producer's exploration strategy.National welfare and security.True cost of purchased reserves.Contractual requirements.

Statistics and comments on trends relative to the above factors are presented where available. (e.g., the degree of correlation between the composite price of oil and gas and drilling costs per foot.)

The conclusion of the paper is that the drilling decision can be made sounder by formalized consideration of a number of economic or quasi-economic factors which lie beyond the realm of quantifiable rate of return projections.
Preventive Maintenance and the Drilling Contractor
Authors: Shepard J. S.
Published: December 2007

No matter what state the drilling industry is in, significant cost savings, and higher profit margins are limited to only a few areas within control of the management of a drilling contractor.

The primary area of cost control is labor, both in terms of rig manning levels and office overhead. Most all drilling contractors still in business today have experienced the harsh reality of cost reduction in this area. However, the rig must still operate, and do so with far greater efficiency than ever before.In terms of dollars, the only major area remaining to substantially reduce costs is in repair and maintenance. Although this can be handled in many different ways, one of the best methods is by having a well designed and implemented Preventie Maintenance (P.M.) System. Such a system can be defined as "a means by which repair and maintenance costs can be controlled both at the rig level, and by upper management, with information needed to make decisions."

For offshore rigs, the number of pieces of equipment that require maintenance can reach upwards to 600 in number. This can translate into thousands of machines for companies with multiple rig fleets. Further, each machine, requires different maintenance at varying frequencies, different skill levels, and is subject to different regulatory requirements, and environmental conditions. For this reason, computerized systems are necessary in order to minimize the overhead burden of administering the system, and to provide fast analytical capability.
Monitoring Engine Oil
Authors: Fullerton R. D.
Published: December 2007

Reduced operating costs and improved engine maintenance can be accomplished through scheduled monitoring of oil samples. Helmerich & Payne International Drilling Co. utilizes an oil sampling service as one method to reduce operating costs and to establish parameters for monitoring the condition of engines.

The purpose of this paper is to discuss the cost effectiveness of implementing an oil sampling service, adherence to sample test results, and the development of parameters by which to efficiently operate the engines. Helmerich & Payne International Drilling Co. uses Caterpillar model D379, D398, and D399 diesel engines as the rigs' primary power source. Over the past four years, the use of an oil sampling service has increased the tiro between oil changes from the recommended 500 service hours to over 1000 service hours. Field data confirms that these extended intervals have translated directly into savings of $200,000.00 in the first three years of the program. As a result, H&P has established new guidelines for engine maintenance. The use of an oil sampling service has allowed H&P to reduce engine operating costs while maintaining its standard of optimum engine performance.
Batchset Optimization on Jolliet Project
Authors: Watkins S. S. , Beato C. L.
Published: December 2007

Conoco's Jolliet Project is a deepwater Tension Leg Well Platform (TLWP) development project in 1758 feet [536m] of water in the Gulf of Mexico. Sixteen 30" [762mm] and 20" [508mm] casing strings were batchset following installation of the drilling template in July, 1987. Batchsetting was expected to reduce the project costs through operational optimization and by decreasing the number of blowout preventer (BOP) stack trips during the drilling phase. The batchsetting operation was completed in 36 days, an average of 2.25 days per well.

This paper discusses the time and cost saved during batchsetting and how the savings were realized through planning and execution. During preplanning, 15 days were saved by improving equipment and procedures and initiating the use of unconventional technology. During the execution, 29 days were saved through use of simultaneous operations, successful troubleshooting of prototype equipment, coordination of logistics, and the use of a rigsite critique system. During the drilling phase, BOP stack trip reduction savings have been estimated at 29 days. Total savings for batchsetting have been estimated at 73 days and $6.6 million.

Planning and execution were improved by the interaction of engineering and operations personnel. This teamwork was the driving force behind the success of batchsetting on Jolliet and directly contributed to optimization savings. It was possible due to management's approach of committing all personnel early in the project. These principles and methodology are not unique, but they have rarely been implemented with this degree of success.
Experience With Effective Drilling
Authors: Remson D. R.
Published: December 2007

Market conditions have established the importance of service quality as the standard by which drilling contractors must compete. Offshore drilling is a cooperative effort in which about 35% of the on-site time involves work tasks that are under the exclusive control of the drilling contractor, and most of the other 65% require his direct involvement to some extent. The way most drilling contracts are structured, the operator actually underwrites the Contractor's performance and thus has every right to expect some sort of service quality guarantee.

When based on timely and accurate data, planning and coordinationapplied to drilling a well can save significant amounts of time and money. They produce not only quicker results but also safer and morepredictable results. This paper presents the experience gained froma program applied to an international fleet of 11 jackup and 2 semi-submersible rigs over a three-year period, 1984 through 1986. Annualincreases in drilling efficiency of 3% were common, predictability was accurate to 97%, overall performance was enhanced during a period of low utilization and falling dayrates.
Development and Implementation of a Universal Subsea Wellhead System
Authors: Dykes C. E. , Hopper H. P. , Jones R. G.
Published: December 2007

The use of exploration and appraisal wells in the development of offshore fields is essential in areas where the majority of new discoveries are likely to be classified as marginal. The initial selection of subsea wellhead equipment can dictate the viability of utilising the well at a later stage. Standardisation and completion flexibility must be incorporated into the specification of subsea wellheads. The paper discusses how this has been achieved by one major operator through the specification of a universal subsea wellhead system.
Drilling With Oil-Based Muds on Offshore Wells: Drilling Contractor's Viewpoint
Authors: Collings B. J. , Stone W. M.
Published: December 2007

While environmental constraints have lessened the desire or will to drill with oil-based muds on offshore wells, the fact remains that use of this type of drilling fluid is an economically sound practice on some wells. Some troublesome shales make it the only way to reach the objective. Unfortunately, the decision to use oil-based mud comes when several attempts, with water-based muds, have failed. Lost hole, lost bottom hole assemblies, and lost MWD equipment result in extremely high well costs for the operator.

When the decision to use oil-based muds does come, the drilling contractor's charge is get the rig to a zero discharge capability, arrange surface equipment, and develop procedures and training for the crews so that drilling with this system is at maximum safety and efficiency. The problem becomes more complex on floaters. The position of the blowout preventers and the difficulty of detecting small gas influxes have created the potential hazard of sudden unloading of the riser before diversion can be accomplished. Surface equipment on most rigs only provides for diverting the flow overboard or taking the surge of mud and gas into the shaker room. Both of these provisions leave much to be desired!

The drilling contractor can improve the situation by attacking the problem with a five step program. This program involves: Pre-planning with the operator to circulate suspected, but undetected gas influxes with positive control.Build a better flow line gas discharge system.Install a better firefighting system in the mud pit room.Install a bleeder valve arrangement to help vent the stack.Crew training on the procedures used in safely handling an oil mud drilling program.
The Planning and Drilling of the World's First Horizontal Well From a Semisubmersible Rig
Authors: Clark A. C. , Cocking D. A.
Published: December 2007

The Cyrus field located in Block 16/28 of the UKCS was discovered in 1979. After appraisal drilling, indications were that conventional wells would not be sufficiently productive to make the field commercial. Therefore, a horizontal well development programme was investigated.

All aspects of horizontal drilling were addressed, in particular those that would allow the bit to be steered to the horizontal from a floating rig. State of the art technology in the form of a drill string simulator was utilised to develop the well trajectories. As the simulator had shown great accuracy on field trials, it allowed the optimum profile to be selected with confidence.

The first well was spudded in June 1988 and drilled 565 m (1854 ft) of horizontal hole through the main producing interval. This paper addresses the main aspects of the planning and drilling of the world's first horizontal well drilled from a semi-submersible rig.
Improved Pressure-Volume Schedules for Circulating Out Kicks in Directional Wells
Authors: Cheatham C. A.
Published: December 2007

While circulating out kicks in directional wells, an industry-accepted practice implicitly assumes that the entire wellbore is slanted at a constant angle. For wells with hole inclinations less than thirty degrees, this assumption is appropriate since the resulting error is small. In highly deviated wells, additional overbalance incurred by neglecting the actual well path can be large enough to cause lost circulation and/or stuck pipe. A method is presented to correct this error for any directional well. Guidelines are given for the common case of build and hold wells.