bluuebunny/crossref_metadata_2025 huggingface dataset:
Detection and Evaluation Methods for In-Situ Gas Hydrates
Authors: Goodman M. A. , Giussani Alberto P. , Alger Robert P.
Published: December 2007

Gas hydrates can occur naturally in subsurface formations under equilibrium pressure conditions. These conditions exist in most arctic and deep offshore regions.1–5

During exploratory drilling for oil and gas in the arctic, operators have encountered insitu hydrates that pose engineering problems. Although these zones are often non-productive, they must be evaluated for well control purposes and well completion design.6–7 The potential of hydrates as an energy resource has also received much attention over the past ten years. Studies of production methods have been undertaken and hydrate coring procedures have been investigated.8–10

With the increased interest in naturally occuring hydrates, the need for improved detection and evaluation methods has also increased. In this paper, logging of hydrates is discussed and selected logs from four arctic wells are examined. A new procedure based on temperature log analysis is described. The concept of a downhole heater for use with drill stem testing is also described for testing and evaluation of hydrate intervals.
Flow Characteristics of Geopressured Reservoirs
Authors: Amirijafari Bahram , Sharer John C. , Rigby Fred Alan
Published: December 2007

A simple mathematical model was developed to simulate production out of a geopressured reservoir about 15,000 ft. deep and injecting the water into a shallow zone of about 6,000 ft. The model represents a two phase (gas/water) flow in a radially symmetric system. Pressure drawdown curves vs. time for a 30-year period are obtained for a constant drawdown rate or a constant well bore pressure.

A sensitivity analysis was performed on some key parameters to determine the impact of gas accumulation in the formation on production. The impacts of various completion choices on the productivity of the well are also discussed.

A successful program for gas production linked to withdrawal of large volumes of water from a geopressured reservoir will require that the well be designed to keep pressure losses in and near the wellbore within acceptable ranges. Effects of tubing size, perforation program, and gravel packing are discussed.
Evaluation of Devonian Shale Reservoir Using Multi-Well Pressure Transient Testing Data
Authors: Lee Byung Oh , Alam Javaid , Sawyer Walter K. , Horan Keith , Frohne Karl-Heinz
Published: December 2007

A multi-well test program designed to study the gas production mechanisms of the eastern Devonian shale reservoirs was completed. Two offset wells were drilled as observation wells in Meigs County, OH. This paper presents the engineering design of the tests, data acquired, analysis techniques, and results of the analysis.

The results indicated a complete anisotropic, layered reservoir system which implies directional gas flow and orientation of natural fractures. This study has provided an insight into the production behavior of reservoirs. It will aid future development of shale gas by optimizing well spacing and understanding of the gas release mechanisms of the Devonian shales.
A Practical Model for Evaluating a Well Producing From a Tight Gas Formation
Authors: Crafton James W. , Poundstone David J. , Brown Charles A.
Published: December 2007

A composite model for gas well performance evaluation and prediction has proven successful and efficient in analyzing gas wells producing from low permeability tight gas formations. By employing analytic methods which model reservoir and fracture behavior, a model has been constructed which is capable of automatic regression for the descriptive reservoir parameters. The model is designed to treat producing and shut-in conditions ranging from a simple four-point test to several years of online pressure-production history. Once history-matched parameters are determined, the model is then capable of projecting future performance.

Field examples of wells producing from tight reservoirs (Eagle; Medina; Niobrara) are presented to demonstrate the applicability of the model in both production performance analysis as well as long term forecasting. These results are compared to finite difference simulation results to demonstrate the model's consistency. In addition, the computational needs of the model in terms of processing time are compared to those of a finite difference simulator.
Evaluation of Below Bubble Point Viscosity Correlations & Construction of a New Neural Network Model
Authors: Ayoub M. A , Raja D. M , Al-Marhoun M. A
Published: December 2007

This paper, precisely, evaluates two famous below bubble point viscosity correlations and tries to create a new Neural Network model for estimating this property. The new created model outperforms the two investigated correlations namely Khan Model (1987) and Labedi Model (1992). The new technique (Artificial neural network) found to be successful in developing a model for predicting viscosity below bubble point with an outstanding correlation coefficient of 99.3%. A limited number of data points have been collected from Pakistani fields in order to construct, test, and validate the model. Viscosity from 99 sets of differential liberation data covering a wide range of pressure, temperature, and oil density were used to validate the correlations and to develop the new model. A series of statistical and graphical analysis were conducted also to show the superiority of the model that has been formulated through an Artificial Neural Network technique. A thorough literature review is also made to check the applicability of the existing correlations and their drawbacks.
Fracture and Permeability Enhancement With Pulse Tailoring
Authors: McHugh Stuart Lawrence , Keough Douglas
Published: December 2007

As part of a DOE program, SRI International performed 1) laboratory experiments to determine borehole-loading-dependent fracture phenomenology and to measure material and fracture properties and 2) computational simulations of fracturing in laboratory experiments and field tests. The fracture data obtained from the laboratory experiments was successfully used to computationally predict the ordering of fracture and permeability enhancement in field tests.
Study on Productivity Evaluation and Performance Prediction Method of Over-pressured, Stress-Sensitive Gas Reservoirs
Authors: Hedong Sun
Published: December 2007

Forecasting the productivity and performance of overpressured, stress-sensitive gas reservoirs is a major challenge for reservoir engineering.

An evaluation method of the effect of stress sensitivity on gas deliverability is presented. This paper introduces a new pressure function, which results from a normalization of the pseudo-pressure and has the dimension of a pressure. Stresssensitive permeability property is taken into account using the permeability modulus. For a practical overpressured, stresssensitive gas reservoir, the gas deliverability is calculated and evaluated. The results show that the decrease degree of gas deliverability is different and it depends on the permeability modulus in the formation on which the gas well is located.

And by combining the binomial equation of gas wells with material balance equation, the basic performance prediction model is established. The tank material balance equation for gas reservoirs has been written taking into account the effective compressibility of formation. The optimum is to determine the compressibility in the laboratory using cores from the reservoir under study. An example is given to show the effectiveness of the new method. The calculation results show that the methods presented in this paper are reliable and correct. The model can preferably predict the production performance in the stable production period and the production decline period of overpressure gas reservoir.
An Experimental Study of Interaction Between Hydraulically Induced and Pre-Existing Fractures
Authors: Blanton Thomas L.
Published: December 2007

Hydraulic fracturing experiments have been performed in the laboratory in pre-fractured material under triaxial states of stress. Tests have been run on naturally fractured blocks of Devonian shale as well as blocks of hydrostone in which the angle of approach of the hydraulic fracture to the pre-fracture was varied in a systematic way. It was found that hydraulic fractures tend to cross pre-existing fractures only under high differential stresses and high angles of approach. In most cases the hydraulic fractures were either diverted or arrested by the pre-existing fractures.
Case History — Obtaining Unit Wide Archeological Clearance to Speed Up Federal APD Approvals
Authors: Hauck Forrest R. , Baumann Richard E.
Published: December 2007

When an extensive amount of oil or gas exploration is projected for a homogenous area which apparently contains a low cultural resource density, a sample survey of the area can be utilized to identify and define environmental variables associated with cultural site presence. Through the implementation of a large scale sampling study, the archeologist can determine those topographic features and vegetation zones containing high to low resource density and can provide the developer with archeological clearance recommendations based upon the site sensitivity of specific environments. This procedure can reduce the need for archeological evaluations in the area by concentrating future examinations in those localities where environmental factors indicate a moderate to high potential for cultural site presence. The Archeological-Environmental Research Corporation (AERC) has successfully utilized this technique on several large areas in the overthrust belt region of northeastern Utah.
Can We Increase Both Penetration Rate and Bit Footage in Hard and Very Hard Formations
Authors: Saif Mohamed Ahmed Abou
Published: December 2007

The author has proved in his doctor thesis1 that the 4-cone 4-nozzle insert-bit2,3 (Fig. 1), patente by the author, has superiour performance than that of the conventional 3-cone 3-nozzle insert-bit (Fig. 2) when drilling was performed both in laboratory and in the field in the same hard and very hard abrasive formations and under the same drilling conditions (weight on bit, rotary speed, and rate of flow of the same drilling fluid).

With the 4-cone insert-bit, footage drilled was more than three times that drilled with the 3-cone insert bit, while penetration rate was about two to three times that of the 3-cone insert-bit.

In the same line, this research work studied and analyized the drilling performance of the 3-cone insert-bit in hard and very hard formations and a solution to the problem "How to increase both penetration rate and bit footage in hard and very hard formations and consequently the unit drilling cost can sharply be reduced" was offered. This includes a new design concerning the distribution and the number of the inserts on the three cones of the bit.
Using Geomechanics to Optimize Field Development Strategy of Deep Gas Reservoir in Saudi Arabia
Authors: Ahmed Mahbub S. , Finkbeiner Thomas , Kannan Adnan A.
Published: December 2007

Saudi Aramco has embarked on drilling long horizontals and maximum reservoir contact (MRC) wells in the deep gas reservoirs. Regional stress field is playing an important role in predicting wellbore stability and future production performance of these wells. To successfully drill and produce these long horizontal wells a detailed geomechanics study and its results needed to be incorporated in the decision tree. Reservoir Management was keen to find the optimum azimuthal direction to place horizontal wells, which will minimize the risk of hole breakouts, optimize drilling mud weights, and ensure sustainable production under depletion mode. A study was undertaken to study the effect of geomechanics on drilling and production of these gas wells. Drilling and production histories along with laboratory measurements were incorporated in the study. The study concluded that horizontal wells should be drilled parallel to the locally derived maximum principal stress (SHmax) azimuth to maximize borehole stability and minimize required mud weights during drilling and production. To date a substantial number of wells have been drilled in the field following the recommended drilling direction that would ensure minimum damage to the reservoir and well's productivity.

The objective of the paper is to illustrate methodologies employed to find the optimum drilling direction causing the least damage to the reservoir and discuss implementation of its findings in the field development.
Smart Model Simplifications to Speed Up Uncertainty Analysis of Integrated Production System Models used for MT forecasting
Authors: van Zandvoord Walrick E. J. J. , Hooimeijer Martijn
Published: December 2007

As part of a study to reduce run times of Probablistic Forecasts iterating around complex Integrated Production System Models, several simplification options have been investigated so that probabilistic forecasts can be created in significantly less time than running many iterations around a full model.

This was achieved through smart model simplification, i.e. selected simplifications where these were expected not to hurt the results and surfacace and subsurface system dependencies.

Based on a representative field model a 35x reduction in run time was achieved. At each stage in the simplification process the results were compared with the full model and the last step was to compare the probabilistic results between the full and simplified model. The probabilistic analysis was based on a Monte Carlo simulation (Latin Hypercube).

The result of this study will help operating companies to perform uncertainty analyses on their 1-2 years forecasts based on integrated production system models, with the right level of simplification. The forecast and the uncertainties can then be used to assist in investment decisions and stakeholder management. Making the wrong forecast may be a problem, but making the wrong assessment of its uncertainties or not providing them at all could seriously affect the reputation.
A New General Formula for Dimensionless Well Inflow Performance Relationship
Authors: Haiquan Zhong , Yingchuan Li , Yulian Wen , Chengjian Li , Wei Li
Published: December 2007

In 1968, Vogel presented an empirical inflow performance relationship (IPR) for solution gas drive reservoirs based on numerical simulation results. However, the relationship lacks in relevant physical significance, and it does not take into account the effect of turbulence that may occur when fluids flow into the wellbore1 at high velocity. Consequently, limitations exist in the theory of deliverability forecast and its application.

Based on the nonlinear-flow mathematical model developed by Forcheimer, a dimensionless IPR for a single phase (oil or gas) is deduced. New IPR formulas for solution gas drive reservoirs as well as partial solution gas drive reservoirs are developed by recognizing the similarity of deliverability equations between linear flow and nonlinear flow of a single phase. And a general dimensionless IPR formula is gained by summing up and normalizing the IPRs in different cases, where characteristic parameters a and n have explicit physical significance. An example is given to compare the new general formula with the exponential equation and Vogel equation. The results show the new IPR formula can predict the well deliverability with high accuracy.
Research and Application on Horizontal Well Sectional Acidizing Technology
Authors: Pei Xiaohan , Zhang Yusheng , Zhang Shujin , Li Qingzhong , Ban Li , Kong Lihong , Wang Jinyou
Published: December 2007

Horizontal well technology is a technological revolution in oil industry, and it is one of the most important methods of thick layer sustainable production and marginal low permeable formation exploitation in Daqing Oilfield. Usually, horizontal wells will suffer damage during the course of drilling, completion and production due to the mud and other organism's pollution. Therefore, acidizing is an effective method to improve conductivity near the wellbore and enhance overall production. However, commingled acidizing cannot guarantee acid being pumped into polluted intervals uniformly owing to long horizontal length (583.7m on average) and heterogeneity formation.

A new composite acid fluid and a novel sectional acidizing technology by inject sealing ball to build the pressure to open sliding sleeves were developed to solve the problem of long interval acid placement. Composite acid system features long corrosion inhibition period, which can improve core permeability by 160% and restore the damaged core permeability by 203%. Sectional acidizing string can resists pressure up to 40MPa and temperature up to 90°C. Four stages ball injection and five intervals treatment can be done in one trip. Moreover, residual acid can be reverse flushed after acidizing.

Up to now, this technology has been applied on 5 wells (18 intervals in total) in Daqing Oilfield. Now satisfactory stimulation results have been achieved. Technical success ratio is 100%; average single well liquid production is increased by 5.2m3/d; oil production is increased by 4.5t/d; and average production enhances by 168%.
Integrated Wellbore/Reservoir Dynamic Simulation
Authors: Hu Bin , Sagen Jan , Chupin Gaël , Haugset Tor , Ek Arild , Sommersel Tor , Xu Zheng Gang , Mantecon Juan Carlos
Published: December 2007

A comprehensive dynamic wellbore/reservoir flow model is successfully built by implicitly coupling a wellbore flow model with a near-wellbore reservoir model. The integrated model can be used to simulate various well flow transients that are subject to wellbore/reservoir dynamic interactions.

In order to evaluate its performance, several hypothetic cases, such as well shut-in/start-up, heading, coning, and crossflow, are simulated. Comparison is made between the integrated approach and the conventional IPR approach, and the advantage of using the integrated model is justified.

With given completion details and early-time reservoir data, the integrated model is then used to simulate a pressure buildup and drawdown test of an appraisal gas well. The simulation results show that the model can easily and accurately match the well testing data only by tuning the skin factor, which indicates the integrated model is suitable for optimizing well testing design, assisting well testing interpretation, and estimating the BHP where downhole measurements are not cost-effective and reliable.
Advanced Geological Modeling and Uncertainty Analysis in a Complex Clastic Gas Reservoir From Saudi Arabia
Authors: Al Maskeen Abdul Mohsen A.
Published: December 2007

This study deals with quantitative detection of factors affecting volumetric uncertainty in Jauf reservoir in Saudi Arabia. The Devonian clastic Jauf reservoir is complex, pinched-out, highly faulted, and stratigraphic trap, limited by an erosional truncation due to a regional Pre Unayzah Unconformity (PUU). The Jauf Formation was developed in a tidally-influenced sequence of shallow marine to fluvial sandstones.

Latest technology for geological modeling allowed the construction of a sophisticated model, integrating various types of data. This complex geological model incorporates a set of faults and an erosional unconformity surface, explicitly determined from seismic, and facies interpreted from core and log evaluation. A special study was conducted to explain the factors of volumetric uncertainty. Structural uncertainties, affecting both the unconformity and faulted blocks, were studied to explain the volume of the reservoir. Additional sensitivity analysis was performed for facies, porosity and gas water contact to evaluate the normalized volumetric uncertainty. Uncertainty analysis was made to identify the number of uncertain attributes. The simulation models were built through the derivative tree of ten different scenarios with hundreds of realizations using critical geological factors such as facies, porosity, structural and fluid contacts. The study showed that, using currently available data, the major factors affecting the uncertainty are the erosional unconformity surface (PUU), and the facies distribution.
Applications of Temperature Transient Analysis for Welltest Interpretation and Well Productivity Evaluation
Authors: Bahrami Nick , Siavoshi Jamal
Published: December 2007

During transient tests, both pressure and temperature change depending on downhole flow rate. In gas producing wells, Joule-Thomson cooling and frictional heating effects are the main dynamic factors that cause flowing bottomhole temperature to differ from the static formation temperature at that depth. When a gas well is shut in, JT cooling effect is vanished and this causes a sudden sharp increase in sandface temperature. Then as the effect of wellbore storage ends, wellbore temperature gradually cools down due to heat conduction with near wellbore region.

This paper demonstrates the applications of temperature transient data and proposes a new technique for using temperature transient data in gas wells in order to determine end of wellbore storage. Also, the effects of permeability and well productivity on temperature behavior are discussed. Three field examples are shown in which both temperature and pressure transient data were analyzed for more accurate welltest interpretation. This paper shows how knowledge of Joule-Thomson cooling effect and frictional heating effect can be applied for reservoir characterization.
Technology Used To Improve Drilling Performance and Primary Cementing Success in Katy Field
Authors: Cowthran James L.
Published: December 2007

This paper presents several improved drilling and cementing techniques utilized by Exxon Company, U.S.A. in the Katy gas field at Katy, Texas. The data presented depicts the results of past versus present field practices in cementing and bit selection. Also included is a description of some problems that, affect drilling operations and cementing in the field. These problems include severe lost circulation, pipe sticking, and cementing failures caused by drawndown Cock-field sands.
Determination of Cuttings Lag in Horizontal and Deviated Wells
Authors: Garcia-Hernandez Augusto , Miska Stefan Z. , Yu Mengjiao , Takach Nicholas E. , Zettner Claudia
Published: December 2007

The objective of this study is to experimentally determine the cuttings lag or slip velocity in horizontal and high-angle borehole configurations. Cuttings lag is a critical component of an accurate determination of the cuttings' source depth, which is important for determining properties (type, strength, porosity, etc.) of drilled formations.

Unique experiments were conducted at simulated downhole conditions using a flow loop with a transparent, 100-ft x 8-in x 4.5-in annulus. In these experiments, the time range for specially marked cuttings to travel through the annulus was measured optically. In addition, cuttings bed height, volumetric cuttings concentration and pressure drop across the test section were measured. The effects of flow rate, pipe rotation, and loop inclination angle on cuttings lag were investigated using two test fluids: water and an aqueous polymer-based (PAC) drilling fluid.

In these experiments, the average cuttings lag was nearly 40% of the fluid velocity (i.e., the cuttings traveled at 60% of the fluid velocity). Pipe rotation increased the cuttings velocity even after accounting for the effect of cuttings bed height on the fluid velocity. A change in inclination from 90 deg (horizontal) to 70 deg reduced the slip velocity by 17%. Three distinct cuttings behaviors were observed: a stationary cuttings bed, a moving layer at the top of the cuttings bed and suspended cuttings. The primary mode for cuttings transport occurred in the moving cuttings layer. The size of this layer was affected by the test fluid.

A cuttings lag model was developed from the experimental data. The model calculates the cuttings source depth given operational parameters (rheology, mud weight, flow rate, hole size, drill pipe size and ROP) for a doublebuild and hold wellpath. This model is a useful tool for drilling optimization and well planning. A better characterization of the formation while drilling helps to make better decisions to optimize drill bit and drilling fluid selection. The model also aids in rate of penetration determination. This improves the drilling process, leading to less drilling time and cost savings.
A Laboratory and Field Evaluation of a Technique for Hydraulic Fracturing Stimulation of Deep Wells
Authors: Conway Michael W. , Harris Lawrence E.
Published: December 2007

ABSTRACTS

In 1981, over 1,000 new wells were drilled below 15,000 feet1. Although bottom hole temperatures in these wells vary widely, all have a number of similar characteristics which make hydraulic fracturing treatments very difficult.

These similarities may include high bottom hole pressures and temperatures, small diameter tubing, high closure pressures, low permeabilities, and tubing contraction problems while treating. The high treating pressures encountered necessitate the use of fluids with minimal pumping friction pressures. The high closure pressures often require the use of high strength proppants which are more difficult to transport than sand. Low formation permeabilities dictate the need for long propped fractures to achieve the desired production increase and thus long term fluid stability is required. To minimize contraction in long tubing strings, treating fluids often must be preheated (100–140°F). The high initial fluid temperatures can alter fluid properties downhole.

The expected effective viscosity of treating fluids as a function of time and temperature are of key importance to the design of stimulation treatments for these wells. In most cases, crosslinked gels are the fluid of choice for stimulation treatments, and most crosslinked fluidsare shear history dependent, therefore possessing no unique rheological characteristics. The variable conditions encountered during the treatment such as tubing size, pump rate, surface fluid temperature and pipe time influence the rheological properties observed.

A laboratory method has been developed to more concisely evaluate the role of the above parameters and data will be presented demonstrating the magnitude of the effects on the time-temperature stability of the crosslinked fluid. Results from both a laboratory and field evaluation of various techniques will be discussed. By achieving conditions where most of the crosslinked fluid viscosity is obtained in the fracture, a much higher viscosity and pipe shear independent fluid is obtained. The rheological data generated on the fluid is also more reliable.
Development and Use of a Simulation Model for Mobility/Conformance Control Using a pH-Sensitive Polymer
Authors: Benson I. , Nghiem L. X. , Bryant S. L. , Sharma M. M. , Huh C.
Published: December 2007

Injection of a pH-sensitive polymer has been proposed recently as a novel deep-penetrating mobility control method, and the development of a simulation capability for its scale-up is reported here. An aqueous dispersion of polymer microgel, whose swelling property shows a strong dependence on pH, preferentially flows into high-permeability zones under acidic conditions. Since the injected fluid viscosity is low, small injection pressures are needed to inject the polymer. Geochemical reactions increase the pH, causing the polymer-containing fluid to experience a viscosity increase of several orders of magnitude thereby altering the flow pattern of subsequently injected fluid. Because the viscosity of microgel dispersions can be controlled with adjustment of pH, this process can be employed both as a deep-penetrating mobility control method (with moderate polymer viscosity) and as a conformance control method (with immobile gel generation).

Polymer-bank placement design and process scale-up requires simulation of transport of microgel, acid-mineral geochemical reactions, pH changes, and the coupling between aqueous phase composition and viscosity. Such a capability has been implemented in a commercial reservoir simulator and preliminary simulations verify the operation and effectiveness of the complex new features, which can describe both the mobility and conformance control applications. Determination of reservoir mineralogy and mineral reaction rates is critical to modeling in-situ pH changes accurately. History matching of coreflood acid injection experiments was used to estimate geochemical reactions and reaction rates occurring in Berea cores. Linear and radial geometry floods in 2-layer reservoir models were carried out as preliminary scale-up simulations. Acidic fluids can be propagated farther into a reservoir in a low-pH state, using high injection velocity, an acid preflush, or weak acids. The Damkohler number was found to be a useful dimensionless quantity for characterizing acid floods with pH-sensitive polymer. Slugs of pH-sensitive polymer improve oil recovery better than continuous polymer flooding or waterflooding.

The simulator was successfully used to history match coreflood experiments, to model techniques to propagate low-pH fluids deep into reservoir, and to demonstrate the effectiveness of pH-sensitive polymer slug treatments for conformance control.
A Study of Gel Degradation, Surface Tension, and Their Impact on the Productivity of Hydraulically Fractured Gas Wells
Authors: Nasr-El-Din H. A. , Al-Mohammed A. M. , Al-Aamri A. D. , Al-Fuwaires O. A.
Published: December 2007

High pH borate gels have been used in fracturing deep gas reservoirs in Saudi Arabia. Guar and hydroxypropyl guar are used at various concentrations up to 45 lb/1000 gals. A breaker (regular or encapsulated oxidizers, guar-specific enzyme, or combinations of these breakers) is usually used to degrade the gel after the fracturing treatment. Field results indicated that the cleaning time following fracturing treatments was too long. Unbroken gel was noted in the flow back samples of some wells. This study was conducted to assess the effectiveness of various breakers that are used in the field, and determine other parameters that may affect the time needed to clean-up fractured wells.

This paper presents the results of a detailed study done to evaluate the performance of several breakers at typical field conditions. The apparent viscosity of various borate gels was measured as a function of breaker type and concentration. Gel degradation was followed in a high temperature/high pressure see-through cell. The surface tension of various gel filtrates was measured as a function of temperature up to 150°C.

Viscosity measurements indicated that all oxidizers degraded high pH borate gels, however the time needed to degrade the gel was found to be a function of breaker type and concentration; temperature and polymer loading. All guar-based gels produced a residue after reacting with the breaker. This residue was noted irrespective of the type and concentration of the breaker used. The residue was noted with gels formed using either guar gum or hydroxylproply guar. This residue may adversely affect the conductivity of the fracture.

Surface tension measurements indicated for the first time that the surface tension of borate gels is high, which will enhance water blockage and hence reduce gas production. This paper examines factors affecting gel degradation, surface tension of borate gel filtrate, and their impact on well productivity.
Effective Acid Diversion and Water Control in Carbonate Reservoirs Using an Associative Polymer Treatment: Case Histories From Saudi Arabia
Authors: Al-Taq Ali A. , Nasr-El-Din Hisham A. , Lajami Ridha A. , Sirra Leopoldo
Published: December 2007

Acid diversion and water control are usually addressed as two separate issues in the oil industry. An associative polymer can be used to simultaneously address these two issues in a single treatment. Associative polymer treatments were successfully applied during matrix acid stimulations in onshore and offshore oil carbonate reservoirs in Saudi Arabia. The oil producers were completed as perforated and open hole wells. The associative polymer was applied in combination with acid treatments mainly to: 1) mitigate the preferential stimulation of water saturated zones located near oil producer layers, 2) improve acid diversion in heterogeneous carbonate reservoirs, and 3) restore the productivity of the damaged wells.

Extensive experimental studies were carried out to investigate potential use of an associative polymer to control water mobility and act as an acid diverter. Coreflood experiments (parallel cores) conducted on reservoir cores at downhole conditions showed that the polymer treatment has no significant effect on the relative permeability to oil. However, the relative permeability to water was significantly reduced. In addition, the associative polymer was very effective in diverting acid into oil-saturated cores.

This paper presents the results obtained from several wells where an associative polymer was applied successfully during matrix acid treatments of damaged wells. All the treatments included stages of associative polymer solutions and 20 wt% HCl with additives. Post stimulation treatments production data, build-up, downhole gauges and production logging confirmed that the associative polymer was very effective in diverting the acid into oil saturated zonesand resulted in a significant reduction in water production.
Tomographic Reconstruction Techniques for Reservoir Monitoring
Authors: Kretzschmar J. L. , Kibbe K. L. , Witterholt E. J.
Published: December 2007

Tomographic reconstruction techniques, using radio frequency electromagnetic wave data, have been applied to the monitoring of fluid distributions at three different enhanced recovery pilot sites.

The attenuation of waves propagating between observation wells was measured at multiple frequencies in the range from 1 to 30 MHz. On two sites more than one pair of wells were available, permitting varied views of the reservoir.

Different versions of published tomographic reconstruction algorithms were applied to both real and synthetic data. The algorithms used include those with both single ray path and lumped system convergence principals.

Results show that tomographic reconstruction requirements vary with reservoir and "system" operations, i.e., well spacing, geometry, frequency, rock/fluid parameters, dynamic range, density of data, and computational techniques. Reconstructions of the same reservoir zone at several frequencies appears to be especially diagnostic.

For those unfamiliar with the terminology, "tomograph" is a "picture of a slice;" in this case a vertical slice bounded by the two boreholes. The reconstruction technology is analogous to that currently used in diagnostic medicine to create "pictures" of the interior of the human body using x-rays or ultrasound.

In "geo-tomography" the probing energy is electromagnetic or elastic (seismic) waves.
Acoustical Anisotropy of Cotton Valley Shale
Authors: Tosaya Carol A.
Published: December 2007

The dynamic elastic stiffnesses of transversely isotropic Cotton Valley silty shale were computed from ultrasonic-frequency compressional-and shear-wave velocity measurements. The measurements were made in three oriented right cylinders of fully water-saturated shale. Confining pressure was varied to 1100 bars for a constant pore pressure of 50 bars.

All velocities and corresponding elastic stiffnesses increased with differential pressure in a manner that suggested continuous closure of pores and cracks and increasing alignment of platy clay particles with pressure. In addition, elastic anisotropy was found to increase with stress level, evidently approaching the intrinsic anisotropy of the zero-porosity, statistically weighted, aggregated volume fraction of the dominant clay mineral.

Expressions for the elastic stiffnesses were derived for the boundary-value problem of plane strain, the conditions for which are approximated by wave-propagation measurements using an ultrasonic-frequency, pulse-transmission technique.
The Filling of Oil Shale Mines With Spent Shale Ash; Ash Characteristics and Grout Development
Authors: Watson George H. , Ziemba Eugene A. , Bissery Paul , Namy Dominique , Griff Robert L. , Nicholson David E.
Published: December 2007

Rio Blanco Oil Shale Company (RBOSC) has considered the modified in-situ (MIS) process as one of the alternatives for extracting oil from oil shale at Tract C-a. One of the problems to be solved for this approach is the environmental consequence of underground retort abandonment. This includes possible contamination of groundwater as the natural groundwater regime is re-established, aerial subsidence, aquifer mixing and underground disposal of surface-retorted materials. This paper outlines the four-phase program under contract to the Department of the Interior, Bureau of Mines, which is being used to address the problem and details the laboratory and pilot scale testing.
Effect of the Sodium and Ammonium Content and the pH of Carbonate Uranium Leachates on the Permeability of a Core From the Catahoula Formation in South Texas
Authors: Otto J. B.
Published: December 2007

This paper reports a laboratory study of the effect of the Na+ and NH4+ content and the pH of carbonate uranium leachates on formation permeability. The purpose of the work was to define conditions such that the leachate would not appreciably decrease formation permeability or cause significant formation damage. The core used in this study was obtained from a uranium zone in the Catahoula formation. It contained about 3% of the expandable clay, smectite, and had a permeability of 2000 md.

Increasing the Na+ content of a leachate 3-fold by a 10-fold increase of the CO3= content from 600 to 6000 ppm by NaHCO3 addition at pH 8 caused a 10% decrease in permeability presumably because more of the smectite had been converted to the swelling Na+ form by ion exchange. Displacement of the 6000 ppm CO3= as NaHCO3 leachate by a 6000 ppm CO3= as (NH4CO)3 leachate at pH 9.4 caused a reversal of the loss in permeability and even a slight increase over the initial permeability presumably because the smectite had been converted to the non-swelling NH4+ form. The effect on formation permeability of Na+ and NH4+ leachates at pH 8 to 9.4, therefore, appears to be reversible. Reversibility of permeability suggests that these leachates do not cause formation damage.

In contrast, a 0.3M NaCl-0.2M NaOH, pH 13, restoration solution used for NH3 removal from formations caused an immediate, irreversible 40% decrease in permeability presumably because the highly caustic solution caused formation damage by chemical reaction with the formation.
Aspects of Slurry and Particle Settling and Placement for Viscous Gravel Packing (AQUAPAC)
Authors: Torrest Robert S.
Published: December 2007

During gravel packing with viscous agueous polymer slurries as in Shell's AQUAPAC, the concentrated suspensions may move at higher velocity than the surrounding fluid. We show here that these concentrated suspensions tend to disperse rapidly in the well-bore. The term "roping" is not a suitable description of the phenomena. Measurements and estimates of single particle settling velocities are presented. The use of such measurements to determine polymer viscosity for field applications is suggested. Finally, since gravel packing calls for fluid placement to the formation, new results for particle placement through perforations show that even dilute 0.25%w polymer solutions give up to 100% placement efficiency for some conditions of interest.
The Flow of Viscous Polymer Solutions for Gravel Packing Through Porous Media
Authors: Torrest Robert S.
Published: December 2007

Gravel packing with viscous aqueous polymer solutions, as in Shell's Aquapac, often calls for fluid placement to the formation. To estimate placement pressures experiments have examined the flow of suitable polymer solutions through porous media ranging from coarse spherical beads to gravel pack gravel and simulated formation sand. The solutions are shown to follow power-law behavior, and pressure drops within the porous media can be described in terms of a simple power-law model. However, the solutions tend to form a gel at the inlet surface of the pack. The surface impairment may dominate the overall pressure drop particularly in the case of formation-like permeabilities. The surface buildup and potentially rapid viscosity breaking may effectively prevent meaningful predictions of pressure response. The results suggest that placement with these solutions may sometimes be very different than intended. Unanticipated high downhole viscosities may suggest interpretations involving "premature sandout." However, breakers can substantially reduce downhole viscosity during placement. Since the nature of gravel pack buildup is strongly dependent on solution viscosity, the detailed behavior may have an important influence on gravel pack effectiveness and productivity.
Multiphase Flow in Porous Media: I. Macroscopic Observations and Modeling
Authors: Salter Stephen J. , Mohanty Kishore K.
Published: December 2007

Tracer displacements were run during steady-state, two-phase flow, where tracers were added to both the wetting and nonwetting phases. Such experiments were conducted in the primary drainage, imbibition, and secondary drainage cycles over a wide range of fractional flows. The effluent tracer profiles from these experiments were fit with a four-parameter, capacitance-dispersion model, which divides each phase into three fractions: flowing, dendritic, and isolated. Mixing in the flowing fraction is described by a dispersion coefficient, and communication between the flowing and dendritic fraction is represented by a single mass transfer coefficient. This model is shown to adequately fit tracer effluent data over a wide range of conditions.

In some areas the model is nonunique--thus, more than one solution fits the experimental data equally well. Additional experiments were conducted to differentiate mechanisms in these regions. The effects of core wettability were investigated and shown to be important. The results of all of these experiments were used to formulate a mechanistic picture of steady, two-phase flow in strongly wetted porous media.
Evaluating the Impact of Waterfrac Technologies on Gas Recovery Efficiency: Case Studies Using Elliptical Flow Production Data Analysis
Authors: Ilk D. , Rushing J. A. , Sullivan R. B. , Blasingame T. A.
Published: December 2007

This paper presents results from an evaluation of water-based hydraulic fracture stimulation treatments (or "waterfracs") performed in the Bossier tight gas sand play in the East Texas Basin. The primary objectives of our study were to not only assess stimulation effectiveness, but also to compare recovery efficiencies of various waterfrac technologies. Our primary evaluation tool is a set of new decline type curves developed specifically for the analysis of production data acquired from the elliptical flow period commonly observed in hydraulically- fractured wells completed in tight gas sands [Amini et al (2007)].

In this study we evaluated 12 gas wells from three Bossier tight gas fields located in Freestone County, Texas. Stimulation treatments for the wells in this study include water-based hydraulic fracture stimulation treatments with little or no sand, cases with large sand concentrations, as well as "hybrid waterfracs." "Hybrid waterfracs" are defined as fracture stimulation treatments where water is pumped initially to create the fracture geometry (i.e., width and length), followed by sandladen gels to transport and place sand in the fracture (presently low concentration gels are used as opposed to large concentration gels used in the 1980s).

Results from our study confirm that "hybrid waterfracs" yield longer, more conductive hydraulic fractures and are more effective at recovering gas-in-place for a given well spacing. Although less expensive to implement, small "waterfracs" (with little or no sand/proppant) are less efficient at gas recovery — which suggests more wells may be required to maximize gas recovery when "waterfracs" are employed.
Succeeding With Multilateral Wells in Complex Channel Sands
Authors: Song Liu , Jianping Li , Dingyu Lv , Kok Jeffrey , Han Shim Yen
Published: December 2007

The lower Minghuazhen is a shallow-water, delta-plain, sedimentary-deposit reservoir sand in Bohai Bay, China. It has relatively heavy oil in place that is high in viscosity. With the understanding that horizontal or multilateral profiled wells are the most favorable design to economically increase individual well production and reservoir drainage, an ambitious program was embarked upon to drill 11 of these wells in the first phase of a drilling campaign.

Although the sand is well defined in offset wells and the structure had been interpreted to correlate between them, Phase I of drilling yielded disappointing results; and only 5 of the planned 11 wells were completed as planned.

To guide the second phase of the development program in which multilaterals were still in favor, a different approach was necessary. The available 3D seismic data was reprocessed using frequency spectrum imaging to better understand target definitions. In addition, Phase I was analyzed in terms of drilling, operational procedures, processes, tools selections and well designs to identify root causes and to learn from them. These studies were then applied to overcome the cannel structural complexities, thus implementing the course of action for seven multilateral wells on Phase II.
Shear Wave Travel Time Determination Using an Unconventional Approach
Authors: Frost Elton , Fertl Walter H.
Published: December 2007

In the past, numerous techniques have been used in attempting the downhole determination of formation shear travel time. These include visual inspection of full wave train recordings (e.g., variable density, signature, microseismogram), monitoring the amplitude characteristics of the acoustic wave train in selected gate(s), digital analysis of the acoustic wave train in selected gate(s), experimentally defining a relationship between compressional and shear wave transmit times, digital analysis of the acoustic wave train at various transmitter-receiver (T-R) spacings, etc. These techniques have had only limited success, particularly in shaly, unconsolidated, undercompacted and/or gas bearing formations.

A new analytical model has been developed and tested which overcomes some of these constraints. By utilizing the standard compressional travel time in conjunction with supplementary non-acoustic logging data, the shear travel time can be estimated with reasonable accuracy in clastic (sand/shale) sequences.