bluuebunny/crossref_metadata_2025_split huggingface dataset:
Differences Between Methane and Condensate Kicks—A Simulation Study
Authors: Szczepanski Richard , Yerlett T. K. , Brown N. P. , Hamilton T. A. P. 
Published: December 2007

Summary
An increasing number of the new developments on the U.K. continental shelf are condensate fields. The properties of condensates are different from those of gases or oils and, consequently, the onset of a kick in a condensate field may give rise to somewhat different surface indications and well-control problems than in the case of a gas kick that is conventionally assumed to be composed of methane.
This paper investigates the differences and similarities between gas kicks and condensate kicks both in water- and oil-based drilling fluids. Information on a wide range of condensate reservoir fluids has been gathered, and four representative fluids have been selected for comparison with methane. The behavior of a kick in a wellbore has been studied using two complementary approaches. First, the volume of a kick as it expands up the wellbore has been calculated by considering the effect of pressure and temperature changes. Second, a simplified dynamic model of a kicking well has been used to simulate the kick-detection and kick-kill phases of well control in a typical deep-well configuration. Although condensates are actually complex multicomponent mixtures, it seems possible to model condensate kicks reasonably well with a simple three-component model that is based on the gas/oil ratio (GOR).
The principal conclusion for safety is that failure to detect a condensate influx on entry to a well will make control of the kick when it reaches the surface more difficult. However, for kicks of the same size, a condensate kick will generally result in surface and shoe pressures less than those for a methane kick. Condensate kicks also should not be more difficult to detect.
Field Experience With Multilaterals in the Idd El Shargi North Dome Field, Qatar
Authors: Scofield J. R. , Laney Bill , Woodard Phil 
Published: December 2007

Summary
This paper describes how one operator used the latest multilateral drilling technology to improve the profitability of the Idd El Shargi North Dome (ISND) field, offshore Qatar (Fig. 1). Dual openhole laterals have been employed to simultaneously exploit the Shuaiba A and B oil reservoirs. In each well drilled to date, the secondary wellbore has been cased off at the lateral junction following drilling of the fullbore lateral section. A mechanical junction has been used to ensure long-term mechanical integrity and re-entry capability following completion. To date, this technology has been used on five wells in the ISND field (IS-74, IS-75, IS-76, IS-77, and IS-80). Approximately 10 additional complex-drainage-architecture wells are planned in 1997 to further develop this field.
Technology Aids Risk Reduction and Transforms Resources Into Reserves
Authors: Caldwell R. H. , Heather D. I. 
Published: December 2007

SummaryChanges in technology can alter status-quo thinking about risk and reward and proved reserves drastically. These changes can be subtle or far reaching and can result in a whole new language to describe their impact; the emergence of "paradigm shift" is an example. Faced with these changes, the decision maker must determine how to evaluate their impact quantitatively.Intuitively, we think of reserves as relatively static quantities, although reserves do fluctuate with changes in price and operating cost (affecting the economic limit) and also with the magnitude of capital costs. Proved undeveloped reserves exist when the required capital investment generates an acceptable return. These reserves become resources when that return requirement is not met. The ability to reduce capital costs and/or risk opens up lower-quality resources to the prospect of economic recovery and the potential to become reserves. Study of the size distribution of such resources shows that small pools can contain successively greater quantities of reserves than pools in larger-size classes. As a result of new technology, development of such pools in a controlled cost and risk environment can represent as great a prize as a large-pool discovery. The ability to "change the rules" because of technology advances opens a vast opportunity for energy self-sufficiency that has ramifications on a national scale.
A Field Test of Surfactant Flooding, Loudon, Illinois
Authors: Pursley S.A. , Healy R.N. , Sandvik E.I. 
Published: December 2007

Illustrated here are procedures that were used to interpret a pilot test of tertiary recovery employing an aqueous solution of petroleum sulfonates. Information derived from a comprehensive tracer program indicated that the effectiveness of the recovery process was reduced by an excessive mixing of surfactant solution with high-salinity formation brine.

Introduction
One of the more difficult phases in the development of any new oil recovery process is the design, implementation, and interpretation of pilot tests. Such tests are usually quite expensive, yet represent only one of the many possible sets of operating conditions. Consequently, the operator should take every possible precaution to choose an optimum set of conditions precaution to choose an optimum set of conditions and to design a pilot that provides maximum opportunities for interpretation. Previous laboratory work had pointed to the effectiveness of surfactants of the type described in the patent literature for use in improved secondary or patent literature for use in improved secondary or tertiary recovery applications. Laboratory studies of these materials had ranged from detailed chemical investigations to floods in reservoir cores, as well as linear and areal models cut from outcrop rock samples. Interspersed with the laboratory studies were field tests that evaluated the injectivity of surfactant systems and pattern oil recovery. This paper describes a surfactant pilot test conducted in a watered-out portion of the Loudon field, Illinois, during the period 1969-1971. In addition to having the usual goal of determining the level of operability in this field, the test was specifically designed to determine (1) the extent of surfactant adsorption-fractionation and the resulting effect on oil recovery, (2) the degree of mobility control achieved and its effect on sweep efficiency and oil recovery, and (3) any additional problems not uncovered in the relatively simple laboratory systems.
Work-Flow Automation Enhances Job Performance and Improves Job-Execution Data
Authors: Schmitzer J. L. , Randall J. D. 
Published: December 2007

Summary
We designed and implemented a work-flow automation system to automate the flow of operational data throughout a servicing operation. Work-flow automation enables well-service personnel who are rarely network-connected to access information systems containing updated job requirements and well data. As the service personnel perform their work, data from the job are stored on a personal computer by use of store-and-forward architecture. Once the computer connects to the wide area network (WAN), job data are forwarded to the service-center operations systems. Copies of these data also can be forwarded to the customer to demonstrate enhanced value or to track cost. In this pilot implementation, we decreased the number of paper forms substantially, increased the quality of data collection, distributed updates to the system to the field easily, and relayed key data to the customer quickly. This paper documents the pilot implementation of this system and the lessons learned from its implementation.
The Permeability of a Uniformly Vuggy Porous Medium
Authors: Neale Graham H. , Nader Walter K. 
Published: December 2007

Abstract
Using the creeping Navier Stokes equation within a spherical cavity and the Darcy equation in the surrounding homogeneous and isotropic porous medium, the flow field in the entire system is evaluated.

Introduction
The objective of this study is the derivation of an engineering formula that shows the interdependence of matrix permeability, km, vug porosity, ɸv, and system permeability, ks , of a uniformly vuggy porous medium.6 In the first section, with the above goal in mind and to satisfy more general interests, we shall study and predict the flow field within a single cavity bounded by a sphere, of radius R, and in the surrounding homogeneous and isotropic porous medium. In the second section, we shall suggest as a generalizing model of a uniformly vuggy, homogeneous and isotropic porous medium a regular cubic array of monosized spherical cavities. Applying the formula for the pressure field near a single spherical cavity, we shall then develop the sought engineering formula.
Bending Torque and Strain Energy in Reeling Coiled Tubing
Authors: Yang Yong S. 
Published: December 2007

Summary
In this paper, formulas for determining torque and strain energy in reeling coiled tubing are derived. The general formula for calculating torque is simplified by using fully plastic deformation replacing elastoplastic deformation. The simplified torque is within 0.25% relative error as compared to the torque formula obtained by using elastoplastic assumption. Most of the strain energy in reeling coiled tubing is dissipated (converted into heat). Only a small part of the total strain energy is recovered. The recovered energy is the elastic energy that is stored during reeling. The stored elastic energy typically accounts for 5% to 15% of the total strain energy in reeling, depending upon tubing and spool sizes as well as tubing material mechanical properties.
Finding the Most Profitable Slug Size
Authors: Jones Stanley C. 
Published: December 2007

Several current sophisticated oil recovery projects involve injection of a slug consisting of a micellar solution, and carbon dioxide or a hydrocarbon solvent. Slug costs combined with low oil saturation may result in marginal economics; thus, the economic success or failure of a miscible project may hinge on choosing the proper slug size. A simple technique will be described here for estimating the "optimum" slug size. Required data include oil price, average oil saturation, per-barrel slug cost, and a slug-size vs oil-recovery curve. The last item is most desirable obtained from pilot floods, but can often be estimated from laboratory data, provided that these results are corrected to allow for heterogeneities of the reservoir in which the flood is to be attempted. Failure to correct for heterogeneities will result in an optimistic prediction of production performance. performance. Profit from a flood is derived from the value of the oil recovered less the cost of slug, and drive fluids, capital expenditures, and operating expenses.
............(1)
Oil recovery hence profit, is a function of, among other things, slug size. Assuming that the per-barrel slug cost is independent of slug size, the maximum profit for given reservoir conditions, oil price, profit for given reservoir conditions, oil price, chemical costs, etc., can be found by setting the partial derivative of a rearrangement of Eq. 2 with respect to slug size equal to zero:
............(2)
Maximum profit occurs when:
................(3)
that is profit is maximum when the slope of the oil-recovery vs slug-size curve is equal to the right-hand side of Eq. 3. Fig. 1 shows four recovery curves. The uppermost curve shows laboratory data for micellar solution floods in which various slug sizes were used. Polymer solutions were used to propagate the slugs through 4-ft.-long-, 3-in.-diameter Berea sandstone cores. The three other curves were computed from these data by assuming that for each of them there were two equal-volume, equal-porosity layers, identical in all respects except for absolute permeability. Oil recovery is reduced with increasing permeability contrast, partly because slug is not equally accepted by the two layers, and partly because the tighter layer is not completely swept before the economic limit is reached. Other recovery curves could be generated, simulating more layers, pattern geometries other than linear, or other desired degrees of complication. Only simple cases are shown here, however, to illustrate the technique of determining optimum slug size. For purposes of illustration, let us assume that the cost of the injected micellar slug, is $5.00/bbl, the average preflood oil saturation is 0.35 and the price received for oil after royalties is $3.00/bbl. For this set of conditions, Cs / (SoPo) is 4.76. Lines of this slope are shifted up or down until they become tangent to the curves of Fig. 1. The point of tangency for each case represents the most profitable slug size.
P. 993
Use of Injection - Falloff Tests To Evaluate Storage Reservoirs
Authors: Mistrot G.A. , Dempsey J.R. 
Published: December 2007

Introduction
Probably the single most important piece of reservoir Probably the single most important piece of reservoir data required in the conversion of a depleted gas field to gas storage service is effective rock permeability distribution, and this information is usually not available in sufficient detail during the primary depletion of the field. Wells are drilled on relatively wide spacing; and core or buildup data, even where available, provide insufficient points of control for adequate provide insufficient points of control for adequate mapping. Matching history with a reservoir simulator can sometimes fill in the gaps, but it is not uncommon for areal history matches to be somewhat insensitive to relatively wide variations in over-all reservoir permeability and individual well descriptive parameters (such as damage, turbulence, and crossflow) at the producing rates at which the field was depleted. producing rates at which the field was depleted. As the field is being converted to storage mode, infill drilling provides the required additional points of control. Normally, good porosity limits can be obtained through logging programs, but permeability is another matter.
Drilling into pressure-depleted reservoirs with gas-or nitrogen-lightened mud is often ruled out from a cost standpoint, and deep invasion is commonplace when nonaerated muds are used. Additionally, costs in general and costs and problems resulting from lost circulation usually preclude extensive coring.
Completed wells more often than not have significant damage and insufficient pressure to flow out invaded and produce at rates and pressures that well permit an acceptable evaluation. In addition to filtrate invasion, it is not uncommon for some solids to drop out, completely blocking the sand face and requiring the well to be acidizing before it will even accept gas on injection. Acidizing - even a small job - is at best a necessary evil as it adds more liquids to an already invaded zone. Deep and severe damage can affect pressure transients for a substantial period of time. period of time. A testing method must be designed that can yield usable information even at low rates and in severely damaged environments.
Field Welding on Oilfield Tubular Goods
Authors: Biron J.N. , Frazier B.G. 
Published: December 2007

Abstract
Examination of several typical samples of field welding of scratcher and centralizer lugs revealed that the quality of welds was inconsistent and generally poor. Damage to the casing could usually be expected. The holding capacity of the welded lugs and of the equipment itself against the lugs was found to be of a very low order.
A non-technical summary of the effects of welding on oilfield tubular goods is presented. It is shown that the tubular goods steels require a stricter welding procedure for quality welds than steels in general industrial use. A study of this will give the busy supervisor a fair appreciation of the problem of joining metals by arc welding.
Having established the effects of welding, the control of these effects as they concern field application is considered. Welding at the rig site is classed into five categories, namely,welding scratcher and centralizer lugs,welding collars, floating equipment,welding casing hangers,orange peeling of conductor to surface pipe, and finally,welding of casing and tubing as piping.
The peculiarities of each category are discussed and recommendations made when applicable.

Introduction
The frequency of holes in casing set in wells gave rise to the suspicion that the failures were related to the field arc welding done on the casing. The welding of scratcher and centralizer stops or lugs on casing is a common practice. It was decided to determine the quality of field welding of these appurtenances to the casing and to evaluate its effect on the wall body. Several typical samples of field welding of scratcher and centralizer stops were examined and tested.
After determining the quality of the welding being done in the field, the next step was to investigate methods of improvement. A review of published literature and consultation with welding engineers provided welding and metallurgical information. Since current laboratory knowledge was not being put to use, translation of the laboratory knowledge into a simple explanation for rig operations was needed. A brief and non-technical discussion of welding on high carbon-alloys steels was prepared to foster a better understanding of the problem by those supervising field welding operations.
A Proven Method for the Control of Incompetent Sand Formations
Authors: Ritch H.B. 
Published: December 2007

Abstract
A sand control process has been developed and field proven in the Gulf Coast. The mechanics of the application involve the use of a gel oil (or gel acid or gel water) as a vehicle to carry sand into or against the formation which has, or is expected to, produce sand. This process is carried on beneath a squeeze tool in order to cope with pressures which might otherwise be unsafe. This process makes it possible to pack a formation without mud or water contamination. After the formation is satisfactorily packed, the packing sand is held in place by a screen liner or sand consolidation plastic. Work has been done to determine the most effective packing sands and gravel. Results of this work are analyzed and tabulated.

Introduction
Sand control problems in the Gulf Coast are as old as oil production in this region. Several sand control methods have been developed; however, there have always been a few wells which defied any sand control measure. It was on wells of this type that the work described in this paper was initially done.
Many variables must be considered when the problem of sand control arises. Virtually all sand control measures are dependent on the bridging of formation particles against some screening mechanism placed in the well. This forms a filter which limits the movement of other formation solids into the well bore.
Certain basic information is desirable when preparing a sand control program:formation sand grain analysis;variations in sand size in individual zones;formation or producing interval thickness:mechanical hookup of well;subsurface depth of producing zone;degree of cementation of formation;lithology;well fluids to be produced (viscosity);bottom hole temperature and bottom hole pressure;quantity of fluid production; andsand control measures previously used and their success.
Some of this well information is difficult to obtain in the Gulf Coast region, due to the difficulty of recovering cores from the poorly consolidated formation.
Using Improved Technology to Obtain Better Cement Jobs on Deep, Hot Liners
Authors: Tragesser Art , Parker P.N. 
Published: December 2007

Critical to the success of a cement job are an accurate knowledge of downhole temperatures, adequate laboratory simulation of field conditions, proper regard for the effects of mud contamination of cement, and efficient proper regard for the effects of mud contamination of cement, and efficient mud displacement. All of these factors are discussed here, particularly in the context of a two-well testing project in Southwest Texas.

Introduction
The design of cementing slurries is always critical on deep wells; however, it is even more so on liner casings because of the performance requirements that exist almost simultaneously at both the top and the bottom of the liner. In cementing full strings of casing, the cement's initial performance is usually judged only in relation to the producing zones near the bottom of the casing. On liner casings, the cement must also set up and provide an adequate seal at the top of the liner, which may be several thousand feet back up the hole. Static formation temperatures at the top of the liner may be much lower than at the bottom. and may in fact be less than the circulating temperature for which the cement slurry was designed. This cement must be efficient in displacing the drilling mud from behind the entire liner, and must have reached the top of the liner sufficiently uncontaminated to set up, it must have adequate compressive strength to hold a pressure test. Mud-contaminated cement at the top of the liner is almost always a problem because of the relatively small volumes of cement required to fill the annulus, and there is a hesitancy to use much excess cement. The use of large volumes of cement behind the drillpipe can have disastrous results if the cement sets up before the drillpipe is removed from the well. In addition to the primary performance criteria discussed above, a deep-liner cementing slurry must also have adequate density to prevent the flow of formation fluids, particularly gas, into the wellbore. The slurry must also have satisfactory rheological properties to prevent formation breakdown while it is properties to prevent formation breakdown while it is being pumped into the annulus. Because many of these factors are ignored, the success ratio of liner cementing has been less than satisfactory. However, analyses indicate that many more successful jobs may be obtained if careful engineering is used to achieve the following:
1. Better analysis of well temperature conditions.
2. Closer laboratory simulation of actual well conditions to yield accurate results.
3. Greater compatibility between oil mud and cement.
4. More thorough mud displacement.
With the objective of improving primary cementing success, these concepts were tested on two wells drilled in areas of Southwest Texas where previous experience showed that conventional approaches were inadequate.