bluuebunny/crossref_metadata_2025 huggingface dataset:
A New Integrated Reservoir Model for F-H Sands in Oritupano B Field, Eastern Venezuela Basin
Authors: Alvarado E. , Camacho M. , Salazar P. , Salas D. , Gonzalez R.
Published: December 2007

The objective of this work was to create an integrated model of the F4U, F4L, F5, F67, F8, H12 and H3U,L clastic reservoirs, within the Lower Miocene Oficina Formation of the Oritupano B field (Eastern Venezuela Basin) in order to evaluate different development alternatives for these reservoirs.

Based on the 3D seismic data reinterpretation, a new model was developed integrating new structural data and sequence stratigraphy as well as defining the different depositional sequences. A new sedimentological interpretation and stratigraphic framework from correlations and two available cores were used to determine the main sedimentary bodies and trends of deposition.

The static model was developed using geostatistical techniques and incorporating the new structural and sedimentological models as well as the available petrophysical data. Stochastic simulations were performed in order to obtain the areal and vertical properties distribution for the different deposits. The results showed consistency with the depositional model previously defined.

Two numerical simulation models were created: a stochastic model, based on the results of the geostatistical analysis, and a deterministic model, based on the new conventional static model. Both simulations yielded similar results. The adjustment of the static/dynamic models allowed the determination of oil reserves associated with these reservoirs and the refinement of the optimal exploitation strategy.

The new geological model indicates that the main structural features of the field are normal faults and extensional reverse drag folds, unlike the preexisting model in which a gentle homocline structure was suggested. A SW-NE depositional trend for the erosive channels and NW-SE depositional trend for coastal bars, parallel to the paleocoastline, were determined. In addition, four depositional sequences were defined formed by transgressive and highstand systems tracts.

Both, the stochastic and the deterministic model suitably represent the dynamic behavior of the studied reservoirs. The communication between the F-H sands of the up-thrown block, with the A9-A13 sands of the down-thrown block, was demonstrated through both dynamic models, which also improved the characterization of the aquifers within the reservoirs. Based on the results of this study, 3 new vertical wells and 5 additional workover wells were recommended. It is expected that these wells will increase the recovery factor of the F-H sands by 12 %.
New Applications of NMR in Understanding Heavy-Oil Behavior
Authors: Romero P. , Quintairos M.
Published: December 2007

Actually in Venezuela reservoir characterization has become very important, especially for heavy oil reservoirs because of the great amount of reserves located in the Orinoco belt. For this reason, new logging techniques like nuclear magnetic resonance are being applied in order to determine petrophysical properties of the reservoirs and fluid characteristics.

The transversal magnetic relaxation time or T2 has been measured to determine the T2 cut-off and fluids saturations of unconsolidated core plugs samples from Melones field. Also the T2 distribution has been measured in heavy oil hydrated and dehydrated samples from Hamaca and Melones fields in the laboratory at different temperatures to obtain the viscosity based on the distribution fitting to gaussian curves.

The effect of temperature increase on heavy oil and water saturated core plugs contributes to a decrease of the oil viscosity, which is observed as a shift of the oil signal to higher T2 times, while the water signal decreases.

The NMR response of core plug samples, saturated with heavy oil, heavy oil with gas in solution and gel is used for calculating the oil and gel saturations, irreducible oil saturation, porosity and the oil volume displaced by gel.

This work presents some of the applications of NMR techniques for a better understanding of the heavy oil reservoirs.
Multilateral-Horizontal Wells Increase Rate and Lower Cost Per Barrel in the Zuata Field, Faja, Venezuela
Authors: Stalder John L. , York Gregory D. , Kopper Robert J. , Curtis Carl M. , Cole Tony L. , Copley Jeffrey H.
Published: December 2007

Petrozuata, C.A is a joint venture (JV) company between Conoco Orinoco Inc. and PDVSA. This JV is developing extra heavy crude in a 74,000-acre block in the Zuata field in the western portion of the Faja del Orinoco in Venezuela.

After the initial single lateral wells were brought on production an opportunity was identified to change the development program to multilateral wells in order to increase production rates. The geometry of multilateral wells is designed to fit the actual sand distribution and depositional environment that ranges from subarial fluvial to marine tidal systems. The various forms of multilateral wells drilled by the JV include stacked dual lateral, stacked triple lateral, gullwing dual lateral, gullwing triple lateral or crow's foot, and pitchfork dual lateral wells. In addition a fishbone multilateral concept consisting of a "spine" or main lateral with liner connected to many ribs or fishbones without liners has been used in single lateral and multilateral configurations. The geologic and geographical reasons for drilling these different types of multilateral wells are reviewed. The result has been an increase in production rate per well that is nearly proportional to the effective lateral length connected to the well bore at a lower cost than possible with single lateral wells of the equivalent length.
Orinoco Oil Belt Well Construction Using "Wells-in-Series" Technology with Horizontal and Multilateral Trajectory
Authors: Silva Boza Gilberto C. , Romero P. Tito H.
Published: December 2007

The Orinoco Oil Belt, located in the southern part of Venezuela, is a gigantic reservoir of 55,000 sq. Km, which contains accumulations of heavy and extra-heavy hydrocarbons of 1,200 MMM barrels of oil in place, and final recovery of 270 MMM barrels. The first well, Canoa N°1, was drilled in 1935. At that time, various multinational companies started exploratory activities in the area. However, due to the oil characteristics, such as low gravity, high viscosity and metals content, the interest of these companies decayed rapidly. Finally, in 1977 the Executive Branch, through the Ministry of Energy and Mines, assigned the responsibility to PDVSA of planning and executing the necessary activities to evaluate and develop the energy resources of Faja.

During the period 1978/1983, an intensive exploration and evaluation program was developed1, including drilling about 1,000 wells, which resulted in a detailed evaluation of the regional geological model, the reservoir characteristics and the crude physicochemical properties. The facility requirements for oil transportation and processing were analyzed as well. Simultaneously, a territorial ordaining of the entire southwestern part of the country was carried out through an Agreement among PDVSA and several Government institutions.

In the early 90′s, as a result of the hydrocarbon worldwide demand forecast and the huge heavy and extra-heavy crude reserves in the Faja, PDVSA, in accordance to the premises established by the Government, decided to promote the creation of Strategic Associations to carry out projects with the aim of fully developing the Faja.
Influence of Asphaltenes Content and Dilution on Heavy Oil Rheology
Authors: Argillier J-F. , Barré L. , Brucy F. , Dournaux J-L. , Hénaut I. , Bouchard R.
Published: December 2007

The increasing oil demand is leading to the development of the very large world resources of heavy oils that are of the same order of magnitude than conventional oils. However, production and transport of these oils are challenging because of their very high viscosities. Our aim in this study was first to understand the role of asphaltenes in these high viscosities and secondly to evaluate the viscosity reduction efficiency when blending with different diluents.

Many previous works studied asphaltene associations in simple organic solvents like toluene or toluene/heptane mixtures, but these conditions are not representative of heavy crude oils. Our approach has been to characterize the rheological behavior of asphaltenes in their natural environment. Samples coming from the same crude oil have been prepared with different asphaltenes contents, from 0 to 20%, after deasphaltating and recombination. From viscosity measurements two concentration regimes were identified: a diluted regime where the apparent viscosity increases linearly with the weight fraction of asphaltenes and a concentrated regime where the viscosity increases dramatically because of asphaltene particles entanglement. The diluted regime can be described as a solution of solvated asphaltene particles that are independent from one another. Natural heavy crude oils correspond to the concentrated regime and the high viscosities observed are due to this entanglement of solvated asphaltene particles. A strong influence of temperature on the rheology is revealed by measured high activation energies.

Dilution of heavy oils has been studied using various solvents, in terms of aromaticity, chemical nature and viscosity. Dilution with low viscosity hydrocarbons, like light crude oil or naphtha, has shown that the viscosity reduction efficiency is controlled by the sole viscosity of the diluent and not by its aromaticity. The aromaticity has no effect up to very high dilution rate, more than 60% in our tests, where flocculation may begin. Results have also shown that blending diluents of different chemical natures and polarities can enhance viscosity reduction. From these observations, the colloidal description of heavy oils can be extended to diluted heavy oils, considered as solutions of asphaltene particles solvated in diluted maltenes.
An Integrated Reservoir Model for Sand Production and Foamy Oil Flow During Cold Heavy Oil Production
Authors: Wang Yarlong , Chen Carl C. , Dusseault Maurice B.
Published: December 2007

Continuous sand production and foamy oil behavior are both believed to be key factors for the enhanced non-thermal fluid production in unconsolidated heavy oil reservoirs in Canada (Alberta and Saskatchewan). The same mechanisms are likely to be active in similar heavy oil strata in Venezuela (Faja del Orinoco), Oman, China (Bohai Bay), and elsewhere. Field experience indicates that fundamental understanding of sand production mechanisms, reservoir fabric alteration, foamy oil behavior, pressure gradient changes, and stress changes are key to successful operations involving massive continuous sanding. Inter-relating these factors requires coupling of geomechanics and fluid flow processes.

An integrated approach incorporating a three-phase, three-dimensional black-oil model coupled with a geomechanics model is introduced in this article. Piping channels ("wormholes") are postulated to develop from perforations when pressure gradients exceed the residual cohesion of the sand. An elastoplastic constitutive model is used to describe the reservoir material before seepage forces liquefy and suspend the sand particles at the advancing tips of wormholes. The hemispherical wormhole tip is postulated to propagate as long as a critical tip pressure gradient is exceeded. A slurry transport model is used to describe the flow inside the wormholes. Field data from Frog Lake, Alberta are used to validate the model, and it appears that the simulation can match the field data remarkably well.
Experiences on Heavy and Extra-Heavy Crude Rod Pumping Automation Applications using Thermal and Dilution Techniques
Authors: Fernandes José , Lastra Alí
Published: December 2007

In heavy and extra-heavy oil production, additionally to the rod-pumping artificial lift method, we must consider using fluid's physical property modification in order to make it easier to produce and distribute. Some methods widely used are steam and dilute injection in order to modify oil viscosity and API, respectively.

Optimizing Alternate Steam processes implies monitoring variations in Steam injections cycles and observe the well production decrement as cycles are completed. One way to optimize production in each cycle is controlling rod-pumping speed, not only to obtain the more production we can, but also to preserve well energy in order to span cycle life. Also, with the information collected, it is possible to make the well by itself indicates when to start a new steam cycle and observe well's declination.

Dilute optimization is a continuous process that considers injection in field and production line. Experiences were collected based on saving dilute injected and obtaining oil production keeping a high cost/benefit relationship.
Applying Curvature and Fracture Analysis to the Placement of Horizontal Wells: Example from the Mabee (San Andres) Reservoir, Texas
Authors: Yuan Qiu , Holtz M. H. , Yang Anping
Published: December 2007

San Andres carbonate reservoirs have long been known to have a high degree of reservoir heterogeneity and poor recovery efficiencies. Fractures are one of several causes of this heterogeneity. The heterogeneity causes unpredictability in water and CO2 flooding. However, the correct placement of horizontal wells can take advantage of this problem.

An integrated reservoir characterization study of the Mabee field incorporating oriented core, Formation Microscanner (FMS) wireline logs, seismic time slices, production character, curvature analysis, and interference testing was used to predict fracture orientation and areas of highest fracture density. These fracture characteristics were then applied to determine horizontal well location and orientation. Fracture orientation was evaluated through the analysis of oriented core, FMS logs, and interference testing, indicating a fracture orientation of N70W. Analysis of the induced fractures in the oriented core indicates that the direction of maximum horizontal compressive stress is N45E. High fracture density was delineated by curvature analysis, relative seismic amplitude, and areas of higher production. Areas with high curvature corre- spond to areas of high relative seismic amplitude and higher production. The data integration indicates that four areas have high fracture density. The synthesis of fracture orientation and density, along with the production character, indicates the optimal location and orientation of horizontal wells.
Water Injectivity Decline Caused by Sand Mobilization: Simulation and Prediction
Authors: Yi X.
Published: December 2007

Water injectivity decline is a very common phenomenon in waterflooding fields. Most of the previous analyses were focusing on water injectivity decline due to the migration of suspended particles in injection water or the injection water/reservoir fluid incompatibility. However, in some unconsolidated formations, another possible mechanism for water injectivity decline is sand mobilization, which means sand particulates separate from rock matrix and move into deep formation. This kind of injectivity decline is controlled by the operation condition of water injection such as injection pressure and injection rate. In this paper, a mathematical model is proposed to simulate the process of sand mobilization and the resultant water injectivity decline.

The mathematical model is derived based on material balance for water, sand particulate, and rock matrix. Also included in this model are particulate generation and deposition constitutive laws, and permeability-porosity correlation. Finite difference scheme is introduced to discretize the partial differential equations and the finite difference equations are solved implicitly through iteration. Sensitivity analysis is performed to study the effects of various factors on water injectivity decline and strategies for managing efficient water injection are proposed through the analysis.
Reservoir Permeability Determination Using After-Closure Period Analysis of Calibration Tests
Authors: Benelkadi Said , Tiab Djebbar
Published: December 2007

Hydraulic fracturing has generally been limited to relatively low-permeability reservoirs. In recent years, the use of hydraulic fracturing has expanded significantly to high permeability reservoirs. The objectives of fracturing low permeability reservoirs and high permeability reservoirs are different and defined by reservoir parameters.

The estimation of reservoir permeability, a variable of great importance in hydraulic fracturing design is frequently unknown because candidate wells either do not flow or a pretreatment pressure transient test is required. Consequently, Nolte has introduced a new method for adding after-closure fracturing analysis to the pretreatment calibration testing sequence that defines fracture geometry and fluid loss characteristics. The exhibition of the radial flow is ensured by conducting a specialized calibration test called mini-fall test. The derivations by Nolte, based on the theory of impulse test and principle of superposition, allow the identification of radial flow and thus the determination of reservoir transmissibility and reservoir pressure.

This study presents a review of the after-closure radial flow analysis. A modified method is proposed to complete the Nolte’s method for the determination of the reservoir transmissibility and reservoir pressure based on the pressure derivative.

The application of the modified method is demonstrated on actual field data from calibration tests performed on several oil and gas wells. The reservoir parameters determined with this method are verified by comparison with results obtained from buildup tests.
Horizontal Injectors Rejuvenate Mature Miscible Flood - South Swan Hills Field
Authors: Edwards K. A. , Anderson B. , Reavie B.
Published: December 2007

The South Swan Hills Unit, located in north-western Alberta, is a carbonate reef with an original-oil-in-place (OOIP) of approximately 850 MM bbl. Waterflooding was begun in the field during the 1960s, and a staged hydrocarbon miscible flood was begun during the 1970s. Chase gas injection was terminated in the mid-1990s. In 1994, however, miscible flooding was reinitiated in the reef margin area of the field using horizontal injectors and reduced well spacing. The reef margin is an area of thick, stacked pay that experienced high gravity override during the original miscible flood. Four patterns have been developed to date. The two earliest patterns have now completed solvent injection and are on chase waterflood. They have both recovered between 800 M bbl and 900 M bbl of incremental oil per pattern (more than 10% of pattern OOIP) from areas which were part of the original miscible flood.

This paper will detail the past history of the pool under miscible flood, the redevelopment of the reef margin area using horizontal miscible injectors, and the performance of the four patterns implemented to date. The factors that have made this redevelopment successful, and their impact on field production, will also be discussed. Finally, plans for future development of this mature field will also be discussed.
Use of Sewage Effluent as a Water Flood Medium Mattoon Pool, Illinois
Authors: Simmons J.D.
Published: December 2007

The Mattoon water flood, located in south Central Illinois, encompasses 450 acres and includes 28 injection and 32 producing wells. A pilot flood utilizing Pennsylvanian age brine proved the feasibility of flooding the Mississippian age formations at Mattoon pool. However, since usable subsurface brines were limited in availability, an expansion of the project could be achieved only after another source of compatible water was found. One such source was the effluent from the municipal sewage disposal system of the city of Mattoon. This effluent carries considerable suspended matter in addition to aerobic and anaerobic bacteria. Following a series of tests, a satisfactory treating method was developed, consisting of chlorination, settling, and filtration. A contract was negotiated with the city of Mattoon to purchase the sewage effluent and injection began in May, 1954.

During the summer of 1955, additional tests revealed that produced water from the oil wells could be mixed with the effluent without additional treating and, during September, 1955, the produced water was introduced into the injection system. Currently, some two and one-half million bbl of sewage effluent have been injected with no permanent plugging of input wells being evidenced. Phosphates, principally of iron, resulting from the presence of detergent soaps in the sewage effluent continue to form after filtration but are readily removed by periodic acid treatments of the wellbores. Although the cost per barrel of water injected is greater than for similar floods using subsurface brines, and considerable time is required to control quality, sewage effluent has proven to be a satisfactory injection water.

Introduction

The Mattoon pool, located along the west side of the city of Mattoon, Illinois, was discovered in June, 1940. Development of the pool proceeded at a moderate pace and was not essentially completed until 1948. Final development included approximately 420 producers and 90 dry holes drilled on 10-acre spacing. The principal producing horizons are the Cypress and Rosiclare sands of the Mississippian Chester series.

During May, 1952, a 70-acre pilot water flood was initiated to evaluate the feasibility of flooding the Cypress and Rosiclare sands. Product ion increases were realized in November, 1952, and by late 1953, results of the pilot indicated that large-scale flooding would be economically attractive. Water requirements for the proposed expansion of the project were in excess of that available from the Pennsylvanian brine used in the pilot. The only other subsurface water source was the Devonian limestone, found at a depth of approximately 3,000 ft. However, since the Devonian brine was sour, its use would be accompanied by relatively high lifting and treating costs, and its availability in sufficient quantities to meet ultimate requirements was uncertain.
Applying a Time-Dependent Darcy Equation for Decline Analysis for Wells of Varying Reservoir Type
Authors: Hsieh Frank S. , Vega Cecilia , Vega Lucy
Published: December 2007

Decline analysis has been widely applied for predicting hydrocarbon reserves. The approach developed by Arps in 1944 not only is still being used but has also served as the basis for which others developed different approaches. However, with modern day computing facilities the analysis can be conducted beyond the process of identifying lines and curves on semi-log/log-log paper as proposed by Arps or matching the history to the type curves as proposed by other authors. A time-dependent Darcy equation allows for analyzing rate-time decline taking into account the reservoir properties that are unique to the well yet vary with pressure/time. Therefore, it can be used to adequately match the slope of the decline curve that is also changing with pressure/time for the same reasons. The time-dependent Darcy equation also allows for generalizing the decline behavior that is unique to a particular geographical region or reservoir type. In turn, this improves the quality of the analysis, particularly, in a situation where only limited production history is available. Rocky mountain field examples are provided to illustrate the simplicity and the effectiveness of the approach.
Restimulating Tight Gas Sand: Case Study of the Codell Formation
Authors: Sencenbaugh R. N. , Lytle D. M. , Birmingham T. J. , Simmons J. C. , Shaefer M. T.
Published: December 2007

Restimulation of wells completed in the Codell formation, a tight gas sand, has proven to be successful in the Wattenberg Field in Colorado. Beginning in 1997, Codell refracturing evolved into a massive program involving hundreds of wells per year. To date, HS Resources has restimulated over 750 Codell wells, increasing reserves and resulting in a project ROR of 100% with finding costs below $4.23 per barrel oil equivalent. This is a case study of the program conducted by HS Resources.

This paper summarizes the refrac program, and its evolution, since its inception. The candidate selection process is examined, as well as geological and operational considerations when restimulating old wells. The evolution of stimulation treatments and fluids are also investigated. The use of 3D fracture simulations, run in real-time during the refracture treatments, and their results are discussed. Finally, both economic and production results are presented.
Cost Control and Improved Production Performance Revive Drilling Program In 20 Year Old, Giant, Sour Gas Field. A Case Study
Authors: Buzarde C. B. , Guyman G. L. , Seal C. A. , Olds K. T. , Foreman J. M.
Published: December 2007

Carter Creek Field is a giant sour gas field, which was put on production in 1982. After initial development the field was plant constrained for many years. In the early 1990's an infill drilling program was attempted. This program was unsuccessful due to high costs and poor production performance. Late in 1997, a joint Chevron - Halliburton team was put together to make another attempt. Though the program initially met with some adversity, the team persevered and eventually solved the problems that had plagued the past. With cost cuts of 35%+ and initial rates that rival the initial rate of the wells that were completed in 1982 (which had twice the pressure), this program has become a top performer.
Data Mining at a Regulatory Agency to Forecast Waterflood Recovery
Authors: Weiss W. W. , Wo Shaochang , Weiss J. W. , Weber James
Published: December 2007

A new method to predict waterflood recovery is presented. The methodology developed in this paper relies on public information and can be used as a first approximation of waterflood recovery in areas where similar regulatory information is available. This study of 140 pre-1980 hearing records identifies factors that are likely to impact the performance of a waterflood in the Nebraska Panhandle.

The hearing records include a maximum of 30 descriptive entries that could influence the success or failure of a waterflood; however, most records contain only a portion of the possible 30 entries. Success or failure is defined by the ratio of secondary to primary oil recovery (S/P). Primary recovery is defined as cumulative oil produced at the time of the hearing and secondary recovery is defined as the oil produced since the hearing date.

Fuzzy ranking curves were used to prioritize the relevance of 30 parameters on the outcome of the proposed waterflood. Both the range and correlation coefficient of a straight-line fit through the curves were used to rank the inputs to develop neural network correlations. Eight parameters were universally available in 42 of the case hearings, but the number of inputs was reduced to six to avoid overtraining problems. These 42 records serve as the database used to correlate the six inputs with the corresponding S/P. A 6-3-1 architecture trained to 90+% yielded consistent predictions. The trained neural network was then used to estimate future oil production from the Cliff Farms Unit. It is interesting to note that a map of the distribution of known S/P values supports the value predicted for the Cliffs Farm Unit.
Completion Effectiveness in the Shannon Formation of the Jepson Draw and Holler Draw Fields, Powder River Basin, Wyoming
Authors: Scott W. A. , Guice W. R.
Published: December 2007

The Jepson and Holler Draw fields are located in the Powder River Basin of northeastern Wyoming. The fields were discovered in 1974 and produce 36° API oil from the Shannon sandstone. The Shannon is a 20 foot thick barrier island deposit that occurs between 9,650-10,025' TVD. The reservoir is currently undergoing pressure support from water injection. All producing and injecting wells need to be hydraulically fracture stimulated to produce or inject at adequate rates. Current activity in Jepson and Holler Draw consists of in-fill drilling of new producers as well as restimulation of old producers. Various job designs, fracturing fluid systems, and proppant types have been tried.

This paper analyzes well performance and the effectiveness of fracture stimulations in the Jepson and Holler Draw fields. Information from stimulation pressure histories was examined with several fracture simulators to predict overall fracture length from the various treatments. Daily post-frac production was then evaluated using the reciprocal productivity index (RPI) graphical production-analysis method and combined with analysis from pressure build-up tests to determine permeability-height (KH) and effective infinite conductivity fracture length. The overall fracture length was then compared to the effective infinite conductivity fracture length using reservoir simulation to examine possible explanations for the difference in the two lengths. This comparison was used to draw conclusions about how job design, fracturing fluid systems, and proppant types affected the well performance.
How Proppant Slugs and Viscous Gel Slugs Have Influenced the Success of Hydraulic Fracturing Applications
Authors: McDaniel B. W. , Stegent N. A. , Ellis R.
Published: December 2007

When hydraulic fracturing techniques are used to stimulate production from an oil or gas well, successful job placement is often jeopardized by near-wellbore (NWB) problems. These problems may be related to the perforation entry or to the fracture width in the immediate vicinity of the wellbore. It has often been concluded that insufficient width generation in the NWB area is the result of the fracture having a very tortuous (rapidly turning or twisted) path for the first few inches or feet before adopting its generally planar shape after it grows beyond the wellbore area. In other cases, the inadequate width problem may result from the generation of several independent fracture planes instead of only one (or a few). During the early 1990's, the oil industry began to consider these problems more seriously, and many operators now use techniques to mitigate such problems before or during a fracture stimulation. The completion plan must sometimes be altered to reduce the occurrence of similar problems in future wells completed in a particular reservoir. Proppant slugs and viscous gel slugs have helped remediate this problem during several applications throughout the world.

Contrary to what we would like to believe, proppant and/or viscous gel slugs do not cure every premature screenout. Of course, some people still believe that these slugs would prevent every premature screenout if they were applied properly for the particular problem. If economics were not a real-life consideration, and every completion could be treated as an experiment, that position might be valid. In today's oil and gas exploration environment, the more practical constraints of "economic benefit" present several limitations. This paper discusses these "slug" techniques and their evolution in recent years. It also presents some of the current state-of-the-art methodologies being used. We also offer practical limits to be considered for use with these techniques. Several case histories are presented as illustrations, and suggestions for alternate completion techniques are discussed.
Friction Pressure Correlation for Guar-Based Hydraulic Fracturing Fluids
Authors: Pandey Vibhas J.
Published: December 2007

Accurate prediction of tubular frictional pressure is an important aspect in design, planning and execution of any hydraulic fracturing operation. Majority of correlations available to predict the tubular friction pressures are based on laboratory generated data. The results from such tests have to be scaled up to predict real time solutions. A novel way to develop such correlation based on actual field data is discussed in this paper. Real time data was obtained for over 300 hydraulic fracturing jobs that were pumped using the Carboxymethylhydroxypropyl guar (CMHPG) fluid systems. This data was analyzed using Fanning friction factor and generalized Reynolds number. Both of these dimensionless entities were modified to accommodate the effects induced by polymeric fluids. Results obtained from the new correlation were able to predict the average surface pressures within 4% of the measured values for over 90% of the data. These results were also compared with a few existing correlations and encouraging conclusions were drawn. Pressure predictions from the new correlation were routinely verified in the field and it was observed that predicted pressures matched the actual in a reasonable range of accuracy.
Plunger-Lift Optimization by Monitoring and Analyzing Well High Frequency Acoustic Signals, Tubing Pressure and Casing Pressure
Authors: McCoy Jim , Rowlan Lynn , Podio A. L.
Published: December 2007

Plunger Lift operations are difficult to optimize due to lack of knowledge of tubing pressure, casing pressure, bottomhole pressure, liquid accumulation in the tubing and location of the plunger. Monitoring the plunger position in the tubing helps the operator (or controller) to optimize the removal of liquids and gas from the well. The plunger position can be tracked from the surface by monitoring acoustic signals generated as the plunger falls down the tubing. When the plunger passes by a tubing collar recess, an acoustic pulse is generated that travels up the gas within the tubing. The acoustic pulses are monitored at the surface, and are converted to an electrical signal by a microphone. The signal is digitized, and the digitized data is stored in a computer. Software processes this data along with the tubing and casing pressure data to display plunger depth, plunger velocity and well pressures vs. time. Plunger arrival at the liquid level in the tubing and plunger arrival at the bottom of the tubing are identified on the time plots. Inflow performance is calculated. Software displays the data and analysis in several formats including a graphical representation of the well showing the tubing and casing pressures, plunger location, gas and liquid volumes and flow rates in the tubing and annulus, and inflow performance relationship at operator selected periodic intervals throughout the cycle. A field case is presented to show how this information is applied to optimization of Plunger Lift operations.
Saturation Height Methods and Their Impact on Volumetric Hydrocarbon in Place Estimates
Authors: Harrison B. , Jing X. D.
Published: December 2007

The paper reviews four of the more popular saturation-height methods employed in the oil and gas industry, namely those proposed by Leverett, Johnson, Cuddy and Skelt. The advantages and drawbacks of each method are highlighted. Each technique is compared by investigating how accurately they model the saturation-height profiles of a Palaeocene oil well from the UK Central Graben and a Permian gas well from the UK Southern North Sea. Both wells have complete data sets including conventional core, SCAL and a comprehensive suite of electric logs. Besides comparing each of the methods on a well basis, the paper applies the resultant saturation-height relationships to the reservoir structures to see the effect on the computed hydrocarbon-in-place estimates. By moving to an areal field-wide basis, the effects of reservoir structural relief and the relative importance of the transition zone modelling is brought into focus.
Propagating Interval Uncertainties In Supervised Pattern Recognition For Reservoir Characterization
Authors: Nivlet P. , Fournier F. , Royer J. J.
Published: December 2007

In the petroleum exploration/production context, characterizing the reservoir quality, identifying the main rock types, or predicting their spatial variations is a challenge for the industry. To achieve this purpose, supervised pattern recognition methods, as discriminant analysis are widely used. These methods aim at calibrating, when possible, a relationship between field features -for example a set of borehole measurements, or a set of seismic attributes- and a predefined set of classes -for example, different rock types-. It has yet the major drawback not to take into account the uncertainties on the measurement arrays, which may cause drastic misinterpretations of reservoir characteristics. The methodology developed is an extension of the standard parametric approach to discriminant analysis. The calibration phase follows the same main steps as the standard algorithm, except that all the processed quantities are intervals. The different interval computations are based on interval arithmetic. Eventually, any imprecise object is assigned to a subset of classes, consistent with the measurements and their uncertainties. As a result, the computed reservoir quality model is less precise, but more realistic, taking into account data and its uncertainties.
Well Planning Quality Improved Using Cooperation between Drilling and Geosciences
Authors: Cayeux Eric , Genevois Jean-Michel , Crepin Stephan , Thibeau Sylvain
Published: December 2007

To improve the quality of well planning and decrease the risks involved in drilling complex wells, E&P companies have been focusing during the last decade on collaborative work of asset team. A new workflow consisting in separating multidisciplinary feasibility evaluation from detailed engineering has now been used on several projects. This workflow decreases dramatically the necessary cycle time to plan a well since only those alternatives that are viable for all disciplines are going through detailed analysis.

The angle block of this method is the combination of a shared earth model with advanced three-dimensional visualisation techniques and quick, but precise evaluation tools. The use of constraints to define default values makes it simple to plan targets and wellbores only with 3D interactive graphic editing. Those constraints can themselves be relative to the structural geological model. Therefore the generated design is accurate enough to be trusted when used by the various evaluation functions. To assess the value and feasibility of a target/well solution, the asset team can use interactively drainable volume, wellbore position uncertainty, driller's target, wellbore collision and drillstring mechanical calculations.

This approach has been used in different contexts for planning wells in an oil field in deep water western Africa and a gas field in Norway. For the field in the golf of Guinea, reservoir simulation has been used to define the location of horizontal drains. In Norway, an extended reach well has been planned using a 3D-reservoir model. The methodology has helped improve the overall understanding of the problem by sharing and explaining each other's constraints, thus improving the well planning quality and reducing the design cycle time.
Optimization of Volumes, Costs, and Reserves through Integrated "Best Practice" Methodologies
Authors: McMurray Mark G.
Published: December 2007

In the E & P business, human resources and technical capability tends to follow growth related capital activities. As a result, "Practice Gaps" form over time in mature fields, compromising value. Cross-disciplinary and collaborative Best Practices ensure producing assets are periodically recalibrated to current technologies, system capacities, and dynamic data. Examples of Best Practices that address asset performance optimization (volumes, costs, and reserves) and portfolio management strategies include Opportunity Assessment and Integrated Well/Field Review processes.

Improved portfolio value can be realized by implementing Best Practice applications to unlock previously unrealized potential. This renewed understanding drives better business decisions affecting such areas as asset retention, asset acquisition, asset divestment, and the appropriate allocation of capital and human resources across the producing portfolio.
Compaction-induced porosity/permeability reduction in sandstone reservoirs:Data and model for elasticity-dominated deformation
Authors: Schutjens P. M. T. M. , Hanssen T. H. , Hettema M. H. H. , Merour J. , de Bree J. Ph. , Coremans J. W. A. , Helliesen G.
Published: December 2007

Open-literature and new experimental compaction data of five reservoir and 16 outcrop sandstones are used to delineate the near-elastic, inelastic and failure domain in 3D-stress space for porosity classes 5 to 15%, 15 to 25% and 25 to 35%. Applications of this compaction-domain model include the analysis of the extent of the near-elastic domain (where elasticity theory can be used to describe and predict rock deformation), the pore volume compressibility (Cpp), and the permeability reduction as a function of reservoir stress path. This is illustrated for a well-consolidated sandstone reservoir with an average porosity of about 18%. Two aspects of dynamic reservoir modeling in the near-elastic domain are addressed: Calculation of Cpp from raw data of volumetric compaction as a function of isotropic total stress change, and the correction of Cpp for a non-hydrostatic reservoir stress path. Open-literature work combined with our experimental data indicates that the compaction-induced permeability reduction of 15-25% porosity sandstone in the near-elastic domain depends predominantly on the increase of the effective mean stress, and not on the reservoir stress path.
A Case History on Integrated Fracture Modeling in a Giant Field
Authors: Al-Ali Z. A. , Stenger B. A.
Published: December 2007

In this paper, a case study is used to demonstrate a straightforward methodology of faults, fractures and high-permeability layers integration in a single porosity single permeability (SPSP) reservoir simulation model. The application of this method in the Ghawar Arab-D reservoir indicated an adequate modeling of the water encroachment pattern.

The described methodology starts with the identification of structural lineaments from 3D seismic data analysis (radius of curvature, coherency analysis), the availability of image logs being critical to validate this early step. Further engineering data such as mud losses during drilling, flowmeter surveys, transient well test interpretations, geochemical analysis and water encroachment patterns are integrated to further describe sealed or conductive fractured areas among the initially picked set of lineaments. Stratiform very high permeability streaks (Super-K) are also described at this stage, resulting in a fine-scale geological model conditioned by engineering data.

Both conductive fractures and stratiform Super-K features are being assigned adequate transmissibility and relative permeability functions in the upscaled reservoir simulation model. Transmissibility values are subject to further adjustments during the history matching process.

Comparison with dual porosity dual permeability (DPDP) modeling is briefly discussed. Cost (CPU time) and benefits of SPSP and DPDP modeling techniques are addressed to conclude that in the present case, the trade-off of implicit fracture/Super-K modeling (SPSP) is compensated by a sufficiently-accurate modeling of the water encroachment pattern and shorter simulation turnover times.
A New Approach to Fluid-Flow Modeling of Directional Permeability in a Faulted Anticline, Little Sand Draw Field, Big Horn Basin, Wyoming.
Authors: Rabaa A. S. , Van Kirk C. W. , Hurley N. F.
Published: December 2007

Little Sand Draw field, Hot Springs County, Wyoming, is a fractured and faulted asymmetric anticlinal oil reservoir. The main producing formation is the Permian Phosphoria Formation. The goal of this project1 was to apply a new geological and engineering approach to simulate directional permeability in a faulted and fractured oil reservoir. The hypothesis to be tested in this study was whether reservoir models with or without tear faults provide a good history match.

Tear faults, which have apparent strike slip offset and occur at high angles to the fold axis, have been quantified at Thermopolis anticline, an analogous structure 6 mi (10 km) to the south. Tear faults are largely unrecognized in subsurface reservoirs and are commonly overlooked in simulations. However, they may have important effects on directional permeability. Anisotropic directional permeabilities, roughly perpendicular to fold axes, are known from pressure-interference tests in the Little Sand Draw field. The spacing of faults in outcrop was used as input for faults in the reservoir model.

A 3-D geological model that correctly honors the structural geology was built using EarthVision (Dynamic Graphics) software. Using the ECLIPSE black-oil simulator (Geoquest, Schlumberger), three fluid-flow models were generated: (1) an unfaulted-unfractured model, (2) a faulted-unfractured model, and (3) a faulted-fractured model which simulated high permeability conduits along the tear faults. Fractures were simulated by assigning permeability anisotropy to the matrix blocks. History matching performed on these models tested which one of them best resembles actual field performance. The unfaulted-unfractured model could not produce enough total fluids to match historical data, and reservoir pressures were too low. The faulted-unfractured model improved the history match, but could not match production data. The faulted-fractured model does the best job of matching the observed past performance at Little Sand Draw.
SubSea MudLift Drilling: Design and Implementation of a Dual Gradient Drilling System
Authors: Eggemeyer J. C. , Akins M. E. , Brainard R. R. , Judge R. A. , Peterman C. P. , Scavone L. J. , Thethi K. S.
Published: December 2007

The subSea MudLift Drilling Joint Industry Project (SMD JIP) completed Phase II of the design and development of a dual gradient subsea pumping system in June 2000. This paper is the last of a series of three discussing the SMD JIP's evolution of dual gradient drilling (see SPE 71357, "subSea MudLift Drilling Joint Industry Project: Delivering Dual Gradient Drilling Technology to Industry"; and SPE 71358, "subSea MudLift Drilling: Planning and Preparation for the First subsea Field Test of a Full-Scale Dual Gradient Drilling System at Green Canyon 136, Gulf of Mexico").1,2

The mudlift pumps (MLPs) and other SMD system components were thoroughly tested in the flow loop at the Hydril Technology Center (HTC), but the components were not yet integrated into a system which could be deployed on an offshore well. The next step was specifying which rig would be used for drilling a selected test well; the rig's specifications would determine how the SMD system integration design progressed. Modifications to the rig would also be necessary to ensure that the SMD system could be safely installed.

The Ocean New Era (Diamond Offshore) was identified as the test rig. This is a 2nd generation 2449 ST VDL rig with 1500ft water depth capability. Once the New Era was selected, both SMD and rig personnel began the parallel tasks of fitting the system to the rig, and modifying the rig to accommodate the additional weight, power requirements and ancillary equipment that the SMD system installation would entail. The dimensions and design of the SMD package were dictated by the size of the rig's moonpool, its BOP handling equipment and the LMRP height.

Based on coordination with rig personnel, the SMD system was assembled in its "rig-adapted" form at HTC, including all manifolding, the seawater power system, the MLPs, and the electronic controls. In compliance with the JIP Basis of Design (BOD), a full-scale factory acceptance test (FAT) of the system was initiated on April 30, 2001 and completed on May 16, 2001. Prior to the FAT, separate testing was performed on certain SMD components not specifically associated with pumping, including the solids processing unit (SPU) and the drillstring valve (DSV). The hydraulic power system along with hydraulic lines, control pod, control cabling and connectors, were all tested in a hyperbaric chamber to simulate deep ocean conditions. A final "endurance" test of the system was conducted before transporting it to the rig at dockside in Galveston. This paper will discuss the parallel efforts of the rig and SMD teams to design, test and integrate the SMD system on the rig. In addition, the results of the FAT and component testing carried out in Phase III, and the lessons learned will be examined.