bluuebunny/crossref_metadata_2025_split huggingface dataset:
Underbalanced Drilling: Praises and Perils
Authors: Bennion D. B. , Thomas F. B. , Bietz R. F. , Bennion D. W. 
Published: December 2007

Summary
Underbalanced drilling (UBD) has been used with increasing frequency to minimize problems associated with invasive formation damage, which often greatly reduce the productivity of oil and gas reservoirs, particularly in openhole horizontal well applications. UBD, when properly designed and executed, minimizes or eliminates problems associated with the invasion of particulate matter into the formation as well as a multitude of other problems such as adverse clay reactions, phase trapping, precipitation, and emulsification, which can be caused by the invasion of incompatible mud filtrates in an overbalanced condition. In many UBD operations, additional benefits are seen because of a reduction in drilling time, greater rates of penetration, increased bit life, a rapid indication of productive reservoir zones, and the potential for dynamic flow testing while drilling.
UBD is not a solution for all formation damage problems. Damage caused by poorly designed and/or executed UBD programs can rival or even greatly exceed that which may occur with a well-designed conventional overbalanced drilling program. Potential downsides and damage mechanisms associated with UBD will be discussed. These include the following.
Increased cost and safety concerns. Difficulty in maintaining a continuously underbalanced condition. Spontaneous imbibition and countercurrent imbibition effects. Glazing, mashing, and mechanically induced wellbore damage. Macroporosity gravity-induced invasion. Difficulty of application in zones of extreme pressure and permeability. Political/career risk associated with championing a new and potentially risky technology. We discuss reservoir parameters required to design an effective underbalanced or overbalanced drilling program, laboratory screening procedures to ascertain the effectiveness of UBD in a specific application and review the types of reservoirs that often present good applications for UBD technology.
Characterization and Prevention of Formation Damage During Horizontal Drilling.
Authors: Yan Jienian , Jiang Guancheng , Wang Fuhua , Fan Weiqing , Su Changming 
Published: December 2007

Summary
The effect of various factors on the productivity of horizontal wells was quantitatively analyzed. The results show that formation damage is an important factor affecting productivity for the low-permeable sandstone formations studied. The effect of formation damage for a horizontal well on production rate is consistently much higher than that for a vertical well drilled in the same formation. The design criteria, formulations, properties, and applications of three low-damaging drilling muds were discussed. It was observed that the three fluids provided excellent formation protection with much lower skin factors and much larger percentages of regained permeability as compared with other commonly used drilling muds. The oil production rates of most horizontal wells are three to five times higher than that of their adjacent vertical wells, which is highly related to the effective prevention of formation damage.
Development of a Commercial Wireline Retrievable Coring System
Authors: Warren Tommy , Powers Jim , Bode David , Carré Eric , Smith Lee 
Published: December 2007

Summary
A wireline retrievable coring system for use with conventional drilling equipment is described. The coring system was developed and tested for application in evaluating coalbed methane prospects where a large quantity of core is required, and it is essential that the core is processed soon after it is cut. A drill plug allows for alternation between coring and drilling without tripping the drill-string. The system is particularly advantageous for coring long intervals, multiple zones relatively close together, or when the exact target depth is unknown. The system has been used to core more than 4940 m (15,057 ft) in Poland, Germany, and France, with a combined core recovery of 94%. In addition, the impact of varying rig costs on total savings is factored into the overall economic evaluation of the system.
Structure H Hydrates: Implications for the Petroleum Industry
Authors: Mehta A. P. , Sloan E. D. 
Published: December 2007

Summary
Structure H (sH) hydrates are unique since their formation requires both a light gas such as methane and molecules typically present in oil and condensates. Several sH formers such as methylcyclopentane, methylcyclohexane, neohexane, and adamantane, are indigenous to petroleum. Phase equilibrium measurements indicate that the temperature and pressure conditions under which sH hydrates form as a stable phase are consistent with those in hydrocarbon production, processing, and transportation facilities. The stable occurrence of sH hydrates calls into question existing hydrate prediction programs and suggests that the hydrate phase itself should be measured, in contrast to previous experimental practice. In this work, we provide a brief overview of the current state-of-the-art on sH hydrates, with an emphasis on its implications for the petroleum industry.
Application of the Gelatin Model for Studying Mobility Ratio Effects
Authors: Burton Melvin B. , Crawford Paul B. 
Published: December 2007

Abstract
A procedure is given which describes how the gelatin model may be used to study the effect of mobility ratio on areas swept before and after breakthrough in fluid injection programs. Differences in mobility ratio are achieved through the proper selection of electrolytes for the invading and displaced fluids. The progress of the front is followed visually and photographed or traced onto plates as desired positions before and after breakthrough. Example applications to standard flooding patterns, vertically and horizontally fractured reservoirs and the in-situ combustion recovery process are presented.

Introduction
In water flooding, gas cycling and other fluid injection programs, the sweep efficiencies and swept areas after breakthrough are known to depend on the mobility ratio. Previous investigators have described the application of the X-ray technique, stepwise use of the potentiometric model and numerical procedures for studying these problems. Others have described the application of the electrolytic and gelatin models for studying sweep efficiencies at a mobility ratio near one. It is a purpose of this paper to describe a procedure for using the gelatin model to study swept areas at mobility ratios other than one.

Procedure
The technique developed for gelatin model studies is composed of four phases: the construction of the model, the selection and preparation of electrolytes, the running procedure, and the recording of the swept areas. Each phase is discussed independently in order that the over-all procedure will not be confused.

Construction of the Model
Since some of the advantages of the gelatin model are its economy, and speed, it is desirable to have as small a model as is possible without creating error through the inability to follow visually the progress of the colored front. For this work, it was found that a distance of 4 to 6 cm between salt bridges is convenient to use. Since the size is relatively small, it follows that the gelatin layer must be thin. For this study, 1/8 in. was used as the gelatin thickness in each case.
Miscible Displacement in a Multiphase System
Authors: Thomas Gene H. , Countryman Gary R. , Fatt Irving 
Published: December 2007

Introduction
Displacement by flooding with a miscible liquid is a possible means for recovering the estimated two-thirds of the oil that remains behind after primary production. The immense economic importance of a process that can recover such large quantities of oil has led to extensive laboratory studies of miscible displacement. As usual in production research, most laboratory studies of miscible displacement have not attempted to reproduce all of the conditions existing in a petroleum reservoir. In the early stages of investigation the need has been for information on the broad, basic principles of the phenomena involved in miscible displacement. The effects of overburden pressure, reservoir temperature, and wettability have been considered of secondary importance. However, one property of a petroleum reservoir which is expected to be of major importance and yet has been omitted from many laboratory studies is the presence of interstitial water.Two possible effects of interstitial water on the displacement mechanism in the hydrocarbon phase immediately come to mind. First, from the generally accepted theory that capillarity governs the distribution of oil and water in porous rock one would expect that for water-wet rock the water will be in the small pores and oil in the large pores. A miscible displacement of oil carried out in the presence of water is operating in a pore size distribution shown in Fig. 1b, whereas if the same test had been performed with only one phase present the pore size distribution is as shown in Fig. la. Although there is not yet a theory of miscible displacement which explains in detail the effect of pore size distribution, one would expect the differences between Figs. 1a and 1b to influence the displacement efficiency.A second factor which may make a multiphase system different from a single-phase system is the presence in the multiphase system of dead-end pores or dendritic structure. Experiments of various kinds on reservoir rock have led to the belief that all pores in the network structure of a porous rock take part in conducting fluid during single phase fluid flow. There are then no dead-end pores and no fingers or dendritic structures containing stagnant fluid.
SPEJ
P. 189^
A New Mathematical Model for Oil/Water Separation in Pipes and Tanks
Authors: Hafskjold Bjørn , Celius H. K. , Aamo O. M. 
Published: December 2007

Summary
In top-side processing, it is observed that the separation rate for water in oil systems increases with the increase in the water cut, and that some water remains in the oil even after long settling times. These features may be qualitatively understood by a combination of coalescence and settling. This work describes a mathematical-numerical model that describes these mechanisms quantitatively. Based on input about system dimensions, flow rate, fluid physical properties, fluid quality and drop size distribution at the inlet, it calculates the quality of the output oil. The model was validated by laboratory experiments and field data.
Development and Testing of a Foam-Gel Technology to Improve Conformance of the Rangely CO2 Flood
Authors: Friedmann F. , Hughes T. L. , Smith M. E. , Hild G. P. , Wilson A. , Davies S. N. 
Published: December 2007

SummaryThirty-six thousand four hundred barrels of CO2 gelled foam were successfully placed via an injector well into the Rangely Weber Sand Unit in Colorado. The treatment objectives were (1) to improve volumetric conformance in this CO2 flood by reducing excessive CO2 breakthrough through fractures, and (2) to increase oil recovery from the associated producers. Local reservoir characteristics indicate the need for a large-volume treatment to achieve these goals. The required treatment volume is beyond the economic limits of standard gel systems. Foam gel technology is one way to economically achieve in-depth conformance improvement at Rangely by replacing 60 to 80% of the liquid phase by the less expensive CO2 phase. A gelled foam system was specifically designed for application to Rangely conformance problems. The field-tested surfactant/gel system was designed according to the following criteria: (1) to produce strong and robust gelled foams under the harsh pH conditions of a CO2 flood, (2) to provide enough gelation delay to achieve the injection of a large foam volume with manageable injectivity reduction, and (3) to considerably reduce the unit cost of the treatment fluid relative to standard non-foamed gel systems. This paper describes the methodology used to design and test the optimum gelled foam system for Rangely. Laboratory results are presented to support the chemicals system selection, including gelation kinetics experiments, surfactant selection, and corefloods with supercritical CO2 at field conditions. The candidate well selection process is described, including injection profile surveys, offset well response, and bypassed reserves calculation. Data taken during the injection phase of the program, including injectivity history and on-site quality control monitoring of the chemical system behavior, are given. Finally a preliminary assessment of the impact of the treatment on CO2 cycling rates and incremental oil production is presented.
Systematic Study of Iron Control Chemicals Used During Well Stimulation
Authors: Taylor K. C. , Nasr-El-Din H. A. , Al-Alawi M. J. 
Published: December 2007

Summary
A new type of experimental procedure was developed to study iron control chemicals in acidizing treatments (citric acid, nitrilo-triacetic acid, and acetic acid) at temperatures from 25 to 95°C. This procedure gives plots of iron in solution versus equilibrium pH, while previous work has generally studied iron concentration in completely spent acid solutions. Hydrochloric acid concentrations of 7.5 to 28 wt %, sodium chloride concentrations of 0 and 5 wt%, and iron (III) concentrations from 1000 to 10 000 mg/kg were examined with varying concentrations of commonly used iron control chemicals. A systematic study of this kind has not previously been reported in the literature. The following new results were found:
Iron (III) hydroxide precipitated from spent acid at much lower values of pH than are generally believed in the literature. The general belief is that iron (III) hydroxide precipitation begins at a pH of about 2.2 and is complete at a pH of 3.3. From experimental results, precipitation begins at pH values of about 1 and is nearly complete by pH 2 at 25°C. As the temperature was increased, iron (III) became significantly less soluble in the spent acid. This means that iron (III) hydroxide precipitation is potentially more damaging to the formation than generally believed. Time-dependent iron precipitation can occur in the absence of iron control chemicals. Time-dependent precipitation of ferric/calcium complexes with nitrilotriacetic acid (NTA) and citric acid was found. In partially spent acid, precipitation of previously unreported complexes containing an iron/calcium/chelating agent in a 1/1/1 mole ratio was observed. This behavior is important because of potential formation damage during the acidizing treatment itself, or during shut-in of the well after stimulation. Synergism with citric acid/acetic acid mixtures was found. These two iron control chemicals were able to prevent iron precipitation better in combination than individually.
Stress Magnitudes from Logs: Effects of Tectonic Strains and Temperature
Authors: Blanton T. L. , Olson J. E. 
Published: December 2007

Summary
An improved method of calibrating in-situ stress logs was validated with data from two wells. Horizontal stress profiles are useful for hydraulic fracture design, wellbore stability analysis, and sand production prediction. The industry-standard method of estimating stresses from logs is based on overburden, Poisson's ratio, and pore pressure effects and gives an estimate of minimum horizontal stress. The model proposed here adds effects of temperature and tectonics and outputs of minimum and maximum horizontal stress magnitudes, which are particularly important to the successful completion of horizontal and deviated wells. This method was validated using data collected from a GRI research well and a Mobil well. Seven microfrac stress tests in GRI's Canyon Gas Sands Well of Sutton County, Texas, provided a means of comparing the predictive capability of different methods. First, one of the seven stress tests was selected as a calibration standard for the stress log. Then the results obtained from the two calibration methods were compared to stress magnitudes from the other six stress tests. This process was repeated using each of the seven stress tests as a calibration standard and comparing predictions to the other six. In every case, the method incorporating tectonic strain and thermal effects produced significantly more accurate values. The Mobil well is located in the Lost Hills Field in California, and pre-frac treatment breakdown tests were used to calibrate a log-derived stress profile. All of the data were used simultaneously to get a best fit for the log-derived stress. The log and its fracture height growth implications compared favorably with available fracture diagnostic data, and maximum horizontal stress values were consistent with published values for a similar, nearby reservoir.
Modeling High-Angle Wells in Laminated Pay Reservoirs
Authors: Fair Phillip S. , Kikani Jitendra , White Christopher D. 
Published: December 2007

Abstract
Productivity improvement and acceleration projects have gained substantially from the success of horizontal well drilling technology. Successful placement of near-horizontal wells in difficult reservoir configurations has become routine. However, not all reservoir situations are amenable to horizontal drilling. Specifically, laminated reservoirs such as thinly bedded turbidites in the Gulf of Mexico (GOM) have been perceived as poor targets. Potentially large reserves are locked in these reservoirs. These laminated turbidite systems have near-zero vertical permeability at the Bouma sequence1 scale and extremely small kv/kh ratios (kv/kh≈0) at the full field, reservoir simulation grid-block scale.
In general, a low well count helps minimize development costs. Highly deviated wells (80°≤ θw&lt;90°) cutting the entire sand package may make it possible to obtain both high field production rates and low well counts. Slanted wells have been known to improve productivity of wells with kv/kh≈0. However, the slanted well model given by Cinco2,3 does not predict any improvement in well productivity for such wells. This apparent paradox is reconciled in this paper.
Bed thickness, well diameter, and well angle determine the geometric pseudoskin of these thin-bedded sequences. For wells that are nearly horizontal, a simple technique is introduced to calculate the geometric skin without complex modeling. The range of validity of this approximation was determined by comparison with fine-grid simulations.
CT Imaging of Wormhole Growth Under Solution-Gas Drive
Authors: Tremblay Bernard , Sedgwick George , Vu Don 
Published: December 2007

Summary
The cold production process has increased primary heavy oil production and has been applied with commercial success in the Lloydminster area (Alberta, Canada). In this process, the production of sand is encouraged in order to form high permeability channels (wormholes) within the formation. The process depends on the formation and flow of foamy oil into the wormholes as these grow away from the wellbore and into the reservoir. The formation and growth of a wormhole was visualized using a computed tomography scanner, in an experiment in which oil flowed through a horizontal sandpack and out an orifice. The only drive mechanism was the formation and expansion of methane bubbles within the live oil. The pressure gradient at the tip of the wormhole was approximately 1 MPa/m when it started to develop at the orifice. Two conditions appear necessary for wormholes to keep growing: (1) the pressure gradient at the tip of the wormhole must be sufficiently large to dislodge the sand grains, (2) the pressure gradient along the wormhole must be large enough to transport the sand from the tip to the orifice. The pressure gradient at the tip of the wormhole was 2.9 MPa/m when it reached its maximum length. This suggests that, although the pressure gradient at the tip was sufficient for erosion to occur, the sand could not be carried along the wormhole causing the wormhole to stop growing. The pressure depletion experiment suggests that wormholes can easily develop in uncemented sand in the field since the maximum oil production rate during wormhole growth (18 cm3/day) was significantly lower than in the field. The minimum pressure gradient (11 kPa/m) necessary for sand transport along the wormhole is important in calculating the extent of wormhole growth in the field.
A New Approach To Evaluate Layer Productivity Before Well Completion
Authors: Prat Giovanni Da , Colo Carlos , Martinez Ramon , Cardinali Guillermo , Conforto Gustavo 
Published: December 2007

Summary
This work presents a new methodology to identify fluid in formation layers and estimate individual reservoir parameters using openhole formation testing techniques. Real-time pressure and fluid identification data are obtained from a new wireline formation testing tool. The tool's dual packer module is needed to isolate individual zones. Field cases from wells located in the San Jorge Gulf basin and in the Neuquen basin illustrate the validity of testing methodology. The reservoir permeability (vertical and horizontal) and formation damage are calculated from pressure transient analysis of buildup and interference pressure data taken from several wells. The results obtained using this technique is consistent with those obtained from testing after well completion (cased hole drillstem test). Evaluation results can be used to decide whether to complete or abandon the tested zone. Fluid type is identified in real time using an optical fluid analyzer. Evaluation of anisotropy on a productive zone scale from the vertical interference test is presented.
Evaluation of Dynamic Pseudofunctions for Reservoir Simulation
Authors: Guzmán R. E. , Giordano Domenico , Fayers F. J. , Godi Antonella , Aziz Khalid 
Published: December 2007

Summary
We present a detailed investigation on the reliability of some of the dynamic pseudofunctions used to upscale flow properties in reservoir simulation. A one-dimensional example (1D) and a real field application are used to evaluate methods developed by Kyte and Berry and Stone, and a new flux weighted potential (FWP) method. A derivation of Stone's method (based on the description given by Stone above) is presented, which is found to give an inconsistent set of equations. Stone's analytical example was used to illustrate how pseudorelative permeabilities that exhibit non-physical behavior may still give acceptable results, but this success can disappear with changes in boundary conditions. The pseudofunctions from a field application were not able to match the 2D simulations from which they were calculated, even when a different pseudofunction was used for each coarse grid block. Improvements were obtained when directional pseudofunctions were used, but still the results were not satisfactory. Similar results were found when comparing fine and coarse grid 3D simulations for a quarter of a five-spot pattern in this field. The results presented in this article suggest that dynamic pseudofunctions, as applied here and as commonly used in industry, may not be an adequate approach to up-scaling. The possibility of large errors and the difficulty in predicting when they may occur make the use of pseudofunctions examined in this paper unreliable.
Aquifer Behavior During Brent Depressurization and the Impact on Neighboring Fields
Authors: Coutts S. D. 
Published: December 2007

Summary
Planning for the depressurization of the Brent Field required an extensive study of the aquifer to determine the withdrawals necessary to depressurize the field and to predict the effect of depressurization on surrounding fields. Static and dynamic aquifer models were constructed and several techniques were applied to evaluate the sealing capacity of the major boundary fault. Since the aquifer extends over several license blocks, integration of a wide range of data of varying quality from different sources was required to build up a complete aquifer model. The results highlighted effects of pressure communication between fields which were not apparent to teams studying individual fields in isolation.