bluuebunny/crossref_metadata_2025 huggingface dataset:
Surface and Downhole Tiltmeter Mapping: An Effective Tool for Monitoring Downhole Drill Cuttings Disposal
Authors: Griffin L. G. , Wright C. A. , Davis E. J. , Wolhar S. L. , Moschovidis Z. A.
Published: December 2007

This paper documents the application and final results of using surface and downhole tilt mapping to monitor and evaluate downhole drill cuttings disposal at the Joint Industry Mounds Drill Cuttings Injection Field Experiment Project. Knowledge of the created hydraulic fractures was critical for determining the placement of "core-through" wells to evaluate the fracturing disposal mechanisms for both sandstone and shale intervals. Through "real-time" monitoring of the fracture it was possible to detect fracture height growth while the test was being performed and measure that the injected fluids stayed in the intended zone. Surface and downhole tiltmeter diagnostics have been widely used for mapping conventional propped and unpropped hydraulic fractures; however, this is the first application of the combination of surface and downhole tiltmeters to evaluate fracture geometry during drill cuttings disposal.

The application of tilt mapping will significantly aid in the advancement of both non-hazardous (drill cuttings and other oil field waste) and hazardous waste disposal by downhole injection. These applications will include: 1) "real-time" monitoring of the actual created fracture geometry allowing injection to be terminated before the fracture grows out of the intended disposal zone, 2) calibration of existing fracturing models by using the diagnostic results, and 3) aiding in the development of new models, if required, for disposal situations.

The combination of surface and downhole tilt fracture mapping determined the location (azimuth and depth) and geometry (height, length and width) of the hydraulic fractures created by injecting drill cuttings. On-site real-time monitoring (with tiltmeters installed in an observation well close to the injection well) indicated that the fractures did not grow out of the target intervals. These results were confirmed by subsequent "core-through" evaluation wells.

The disposal of waste by downhole injection has proven to be an economically and environmentally attractive solution. The key to moving this method forward is to develop and implement technology that will convince the regulatory community that this is safe, reliable, and permanent. Tiltmeter fracture mapping has played a key role to date, and will continue to, in achieving this goal.
Phase Separation Using a Simple T-Junction
Authors: Azzopardi B. J. , Rea S.
Published: December 2007

Gas/liquid flow dividing at a T-junction can exhibit significant phase maldistribution. This has potential as a simple, compact (partial) phase separator. Though there is by now a reasonable body of knowledge on the performance of such junctions, the data is predominantly for air/water at near atmospheric pressures in small diameter equipment. Moreover, there is as yet no agreed criterion to identify at what conditions and for with what geometry a T-junction is a good (partial) phase separator.

This paper presents data from a field trial in which a T-junction was placed on the outlet line from an onshore well. Data were obtained on the phase split at the junction for a number of inlet flow rates and for different resistances in the two outlet legs of the junction. The trends in the data are compared to those for other published work. In addition, a criterion is suggested for good phase separation. The present data, together with that from the literature are then examined and a method for specifying conditions for good phase separation is presented.
A New Approach Solves Differential Sticking Problems in Geleki and Ahmedabad Fields
Authors: Pal Krishan , Mangla V. K. , Joshi N. P. , Tewari P. P. , Bose U. N.
Published: December 2007

Differential sticking is one of the major downhole complications encountered in drilling operations. Generally oil base spotting fluids are used to release the stuck ups. However, the results are not always good.

Based on sticking severity in the laboratory experiments, differential sticking has been classified into two major categories viz.; normal and extreme differential sticking. Sticking of first category can be released by using conventional oil base spotting technique, however, it fails to release the extreme stuck ups which invariably results in operations like jarring, washover, side tracking etc. and leads to loss of considerable precious rig days, costly drill string and/ or loss of the well.

In order to meet the challenges of such extreme stuck ups, a new acid based formulation (Formulation- A) has been developed. It reacts chemically with the cake instantaneously and destroys it. The chemical destruction of the cake leads to the release of both types i.e. extreme as well as normal differential sticking. It has no adverse effect on the properties of drilling fluid and is also non damaging to the drill string.

The two case histories i.e. in the deep well no. GGG, TD- 2900 m. with horizontal drift of 660 m. in the Geleki field and high drift well no. AAA, TD-1835 m. with horizontal drift 904 m. in Ahmedabad field prove the usefulness and effectiveness of this formulation in releasing more than 7 days old severe stuck ups. Said formulation designed in tune with the expected contact area exhibited excellent results with quick release of stuck ups. This technique has since been widely accepted for the use in extreme cases of stuck ups.
Frequently Asked Questions in Well Test Analysis
Authors: Daungkaew S. , Hollaender F. , Gringarten A. C.
Published: December 2007

Despite the tremendous progress achieved in well test analysis in the last twenty years, many important and practical questions that are frequently asked by practicing engineers have received little attention in the literature. Three of these are addressed in this paper. The first one is whether it is possible to obtain more information from build-up data than from drawdown data in a testing sequence. By introducing a new definition of the radius of investigation – as opposed to the radius of drainage – based on the ability to interpret data using pressure derivatives, we show that the information obtainable from a long build-up following a short drawdown is actually limited by the gauge accuracy and noises as the shut-in time increases. The second frequently asked question (FAQ) relates to the minimum amount of detailed rate history which is required in order to obtain correct pressure derivatives, as a truncated or averaged rate histories may modify the derivative shapes at late times and therefore induce erroneous interpretations. A new rule of thumb is proposed, which combines the most recent flow-rate history with an effective time based on a fraction of the cumulative well production. The last FAQ concerns the possibility to distinguish a non-uniform mechanical skin effect from a uniform one from well test data. Current interpretations with fully penetrating wells yield a single value for the mechanical skin effect, which implicitly assumes that damage is uniform over the well surface. Various skin distributions are investigated with a multilayered model to determine how a non-uniform skin distribution around the wellbore affects the interpretation. It is shown that non-uniform skin distribution can be identified during specific flow-regimes and therefore must be taken into account in the interpretation.
Well Testing with a Permanent Monitoring System
Authors: Tibold M. P. , Simonian S. , Chawla M. , Akbar M.
Published: December 2007

An extended welltest was successfully performed on a deep, sour, high-pressure, high temperature remote onshore appraisal well using a permanent downhole monitoring system. Prior to the six-month extended test an initial test and stimulation treatment was performed on the well. The permanent monitoring system provided continuous pressure, temperature and rate measurement data in a technically challenging completion environment. Complete and accurate data was obtained on-line for performance monitoring, reservoir simulation and analytical test analysis. Unforeseen completion challenges and wellbore restrictions would have resulted in alternative conventional data collection methods yielding severely restricted data suites and test results.
Anti-Agglomerant Hydrate Inhibitors for Prevention of Hydrate Plugs in Deepwater Systems
Authors: Frostman L. M.
Published: December 2007

Anti-agglomerant low dosage hydrate inhibitors (LDHI’s) give operators an additional tool for controlling hydrates in their systems. In contrast to kinetic and thermodynamic hydrate inhibitors, anti-agglomerant LDHI’s inhibit hydrate plugging, rather than hydrate formation. Thus anti-agglomerant LDHI’s allow hydrates to form but keep the particles small and well dispersed. Fluid viscosity remains low, allowing the hydrates to be transported along with the produced fluids. Emulsification of the produced fluids is not necessary; in fact, anti-agglomerant LDHI’s have aided in demulsifying several black oil emulsions. In the laboratory, anti-agglomerant LDHI’s have been shown to be effective up to 40 °F below the hydrate formation temperature, at pressures up to 7000 psi, and for shut-ins up to two weeks in duration. In addition, extensive laboratory testing and formulation work have been performed to ensure that the anti-agglomerant LDHI’s are compatible with system metals, elastomers, and treatment chemicals, and that the products will not plug umbilicals nor cause upsets in surface facilities. After a comprehensive laboratory evaluation, an anti-agglomerant LDHI was selected for field testing in a deepwater, Gulf of Mexico oil well. The product protected the system throughout the 1.5 month trial, including two brief shut-ins. This paper presents the results of the laboratory and field tests.
Repeated Seismic Survey From the North Sea using New Streamer Technology
Authors: Eiken Ola , Svendsen Morten , Navrestad Torstein , Haavarstein Erik , Larsen Leif
Published: December 2007

Seismic reservoir monitoring is now a well established technology. The method has a yet unrealized potensial which will open for wider use, if higher repeatability can be obtained. Wider applications could be more quantitative interpretations, monitoring over shorter time intervals and application of the technology to smaller, tighter and more complex reservoirs. Todays towed streamers impose basic limitations on repeatability, as streamer feather is hard to repeat and tow noise must be kept low. New streamer technology, called Q-Marine, involves single hydrophone sensor output instead of hardwired groups, improved acoustic positioning and horizontal steering of the streamers. This enables a better attenuation of tow noise, as induced from either swell or flow across the streamers. The horizontal steering makes repeated streamer positions possible. In the first full-scale use of the system, data will August 2000 be acquired over a major producing field in the North Sea, as a repeat of multi-streamer lines after a time-lapse of three years. This test is expected to show the increased monitoring power of the new system, with detection of only a few meters movement of saturation fronts.
Integrated Flow Modeling: The Fusion of Geophysics and Reservoir Engineering
Authors: Pagano Theodore A. , Fanchi John R. , Davis Thomas L.
Published: December 2007

The application of three-dimensional (3D), time-lapse seismic monitoring is rapidly becoming a prevalent tool in the oil and gas industry. Time-lapse seismic monitoring can dramatically improve reservoir understanding and consequent ultimate recovery factors. However, 4D seismic monitoring is not applicable to all reservoirs and all development strategies. A strong 4D seismic candidate must not only have favorable geophysical rock properties, but must also have a development plan that encourages observable changes in repeat 3D seismic surveys. A traditional flow simulator that includes a petrophysical model has the ability to predict ‘dynamic’ reservoir changes and the resultant changes in seismic response. This inter-discipline approach to reservoir modeling blurs the distinction between geophysics and reservoir engineering. This ‘integrated flow model’ is a powerful tool that can be used to determine the feasibility of a 4D seismic monitoring project before initiation. In addition, it can be used throughout the life of the monitoring project to ensure a correct and thorough understanding of the reservoir as it matures.
Integrated Approach to Infer Fractures and Manage the Waterflood Projects in Mauddud Reservoir, Raudhatain & Sabiriyah Fields, North Kuwait
Authors: Al-Ajmi Hussain Zayed , Chetri Hom Bahadur
Published: December 2007

Mauddud limestones are multi-billion barrel depletion drive reservoirs undergoing massive development efforts with a planned 700% increase in oil production through pattern waterflood. The conceptual development plan for the reservoir, in view of uncertainty about the degree of fracturing and its resultant impact, has been kept flexible allowing for a change in development strategy, if deemed necessary.

A review of the performance of historical offtake points and data acquired so far illustrates a large variation in static and dynamic behavior areally as well as vertically. Integration of multi-source evidences to describe the anomalies and infer the probable existence of fractures is done to predict the impact on the inverted 9-spot waterflood patterns likely to be operative next year. The integrated approach illustrates the significance of fluid & rock data, Pressure-Production data and information obtained from new & old logs to revisit the reservoir description for inferring fractures.

Recently acquired 3-D seismic data exhibited faults of various magnitudes scattered over the major area of historical offtake. The spread of cumulative production, well PI and Qmax areally revealed a linkage between the faulted & non-faulted area. A review of past PBU data coupled with core data further indicated the existence of fractures. A review of resistivity and caliper response in old logs and interpretation of image logs also deciphered the presence of fractures. Scanning through the drilling and completion histories of wells was done to authenticate the inferred fractures in Mauddud reservoir. The performance of the two waterflood pilots in operation was also reviewed to see areal and vertical connectivity utilizing the Pressure-production and RFT/PLT data to infer any flow through the fracture system.

Preliminary studies indicate that 7 inverted nine spot patterns (one-fourth of the total number of patterns) are likely to be impacted by the fractures due to premature breakthrough of water injected and reduction in the sweep efficiency. Analytical methods indicate the loss in recovery to the extent of 12 to 18% if significant fractures are present within the patterns. However, in case of minor degree of fracturing, Injectivities and sweep efficiency may improve.

In light of uncertainties on extent of fracturing, future work plan includes review of core, Image logs & productivity/Injectivity data from new wells and Pressure Build up data gathering with bottom hole shutting- in in key wells.

The integrated approach has helped to understand the flow dynamics of injected water better and recommendations leading to better management of the water injection project for Mauddud reservoir.
An Investigation of Three-Phase Counter-Current Flow Using X-Ray Computerized Tomography and Neuro-Simulation Modeling
Authors: Al-Wadahi M. , Grader A. S. , Ertekin T.
Published: December 2007

This work examines the physics of three-phase counter-current fluid flow driven by gravity and capillary transport mechanisms through a combination of experimental measurements and neuro-simulation modeling. There have been only a few scientific reports in the literature addressing counter-current flow phenomena, especially under three-phase flow conditions. Counter-current flow driven by gravity and capillarity may occur in fractured reservoirs (both in matrix and fractures), in solution gas drive and gas cap reservoirs with high vertical permeability, and in some water-flooding operations.

Three-phase flow experiments were conducted with an idealized system and the temporal and spatial saturation distributions during counter-current flow periods were acquired using computerized tomography. The experimental results were simulated using a conventional reservoir simulator. The simulation results provided the basis for training an artificial neural network through which the best relative permeability and capillary pressure functions that match the experimental data were obtained using a pattern recognition protocol.
Laboratory Based Evaluation of Gas Well Deliverability Loss Due to Waterblocking
Authors: Kamath Jairam , Laroche Catherine
Published: December 2007

Waterblocking due to invasion of completion fluids has been suspected to reduce gas well deliverability.1–5 However, this effect has not been quantified. We report results of a laboratory program to measure the waterblocking effect in core samples from a gas field. These data were mapped to a wellbore model to make deliverability predictions.

The laboratory data consist of gas flow rate as a function of injected gas pore volume for various liquids (brine, methanol, toluene, isopropyl alcohol, and brine-methanol mixtures) at two saturation states (fully saturated with liquid, and containing liquid and trapped gas). We injected over 10 000 PV of gas in each test to mimic near well bore conditions. The data showed that the liquid displacement regime was followed by a mass transfer regime.

The wellbore model had a time varying skin to account for the cleanup of the fluid invaded ("waterblocked") region. Clean up occurs as gas flows past this high liquid saturated region and removes liquid by displacement and mass transfer. We used the laboratory data to relate the reduced permeability of this region to pore volumes of gas throughput.

We find that any loss in gas well deliverability recovers in two phases. The first phase corresponds to fluid displacement ("flowback period") and lasts for a few days at most. The second phase is slower and can last several months. Here evaporation causes the deliverability to slowly increase. It is in this regime that adding volatile fluids, such as methanol, to the completion brines has advantages.
Fracture Pressure Slope Analysis for TSO’s in High-Permeability Formations
Authors: Smith Jeffrey E. , Meyer Bruce R. , Jacot R. Henry
Published: December 2007

The relative popularity and success of the frac & pack technique in hydraulic fracturing has resulted in some misconceptions regarding the objective, procedure and pressure analysis after a screen-out. This paper addresses frac & pack procedures and the pressure response after a tip screen-out (TSO).

An analytical method has been developed for analyzing pressure slope behavior after a TSO in high permeability formations. These equations incorporate the first order parameters affecting the fracture pressure, rate of change of pressure (derivative) and pressure slope behaviors after a screen-out.

The fundamental equations for pressure slope analysis are similar to those originally developed by Nolte for pressure decline analysis. The major difference is that after the fracture stops propagating (i.e., after a TSO) the injection rate is not zero. Consequently, if the injection rate is greater than the leakoff rate, the fracture volume and net pressure (constant compliance) must increase. If the injection rate falls below the leakoff rate, the fracture net pressure must decrease.

Although analytical equations will not replace three dimensional fracturing simulators normally used for design and realtime history matching, they do provide insight into the major parameters affecting pressure behavior after a TSO without running a numerical simulator. The analytical equations presented in this paper demonstrate why pressure slopes after a screen-out are typically much greater than unity for low efficiency fractures.

A generalized set of equations is presented for analyzing the pressure slope behavior after a screen-out. Numerous graphs are provided which illustrate the parametric effects of fracture efficiency, spurt loss and fracture net pressure at the time of a screen-out on the pressure, derivative and slope behaviors after a TSO. Comparisons of the analytical pressure slope equations with a three dimensional fracturing simulator are presented to show the application of the analysis.

A new methodology of frac & pack post analysis is presented using the pressure slope technique. This methodology utilizes the pressure slope during a screen-out as a check on the minifrac and fracture efficiency. Two frac & pack cases with bottomhole data are analyzed using a three dimensional hydraulic fracturing simulator to illustrate the pressure slope analysis for low efficiency fractures.
Three-Dimensional Calculation and Visualization of Fault Gouge Ratio
Authors: Hoffman Karen S. , Neave John W.
Published: December 2007

Understanding the sealing characteristics of faults is critical in assessing the hydrocarbon potential of traps formed by faults. Fault gouge ratio and juxtaposition analysis have often been limited to a single cross section (a two-dimensional approach) or to a single, isolated fault surface (a partial three-dimensional approach). We have now developed a full three-dimensional solution for calculating fault gouge ratio. This method uses a continually varying clay volume fraction, a network of faults (isolated, dying and/or branching), and displacement along the fault surface (instead of just the dip component). The structural model used as the framework for this calculation is based on geometric reconstruction techniques that construct faults and horizons in three-dimensional space, allowing easy and rigorous calculation of juxtaposition and displacement. These last two items are necessary input to the fault gouge ratio calculation.

The steps in calculating fault gouge ratio in three-dimensional space are as follows: (1) create structural framework, (2) calculate volume of clay (Vcl) as a continually varying property within this structural framework, (3) determine displacement, allowing for oblique slip, and (4) calculate fault gouge ratio for hanging wall and foot wall blocks, and sum to determine the ratio for every point on the fault

Rigorous calculation of fault gouge ratio depends on a robust structural model. With the model described herein, a variety of scenarios may be investigated, thus incorporating uncertainty into the calculation. Determining whether a fault will act as a seal, or whether there is potential for development of leaks during the production of the reservoir depends on many variables. Minimizing the uncertainty in this part of the analysis may provide increased confidence in assessing risk.
NMR Logging Improves Wellsite Efficiency, Completion Decisions, and Formation Evaluation in a Freshwater, Shaly Reservoir
Authors: Moraes Jose-Jorge , Brandao Renilton , Tellez Ricardo , Vallejo Jaime , Garcia German , Singer Julian
Published: December 2007

Rio Ceibas is a freshwater shaly reservoir in the Honda formation of Colombia. A typical well has 15+ sands, which may contain light oil, medium oil or mobile water. Formation evaluation is difficult. The fresh water and the high volume of smectite clay cause resistivity logs to respond more to the volume of clay than to the difference between oil and water. Nuclear measurements do not indicate clearly the most productive intervals. A focused effort was started in 1998 to increase production using cost-effective modern technology, one element of which was the introduction of nuclear magnetic resonance (NMR) logs.

At the wellsite, NMR permeability is used to choose points for wireline pressure tests. The percentage of dry tests has been reduced from 24% to 7%. This saves significant rig time since pressures must be monitored regularly in many sands. As verified on cores, the presence of an NMR signal with T2 > 300ms is a sign of light hydrocarbons. When other data are inconclusive, this indicator helps to decide whether to perforate a sand. NMR free fluid and permeability are then used to decide which intervals in the sands have the best producibility. This method saves costs by reducing perforating intervals without reducing production.

For reservoir description, NMR has contributed to improved estimates of effective porosity, and qualitative permeability. Both cores and logs have been analyzed to establish interpretation parameters such as bound- and clay- water cutoffs, and permeability coefficients. In those sands that produce clean oil, the irreducible water from NMR logs is an indicator of water saturation, because of the difficulty of obtaining a reliable value from conventional logs. It is also used to determine resistivity interpretation parameters for calculations in other sands. The new formation evaluation procedure improves the match between predicted and actual production.
Correlations of NMR Relaxation Time with Viscosity, Diffusivity, and Gas/Oil Ratio of Methane/Hydrocarbon Mixtures
Authors: Lo Sho-Wei , Hirasaki George J. , House Waylon V. , Kobayashi Riki
Published: December 2007

Viscosity, diffusivity, relaxation time and gas/oil ratio are important properties in the characterization of reservoirs by NMR well logging and in prediction of production performance. For the past few years, NMR well logging has been used to estimate the formation properties and hydrocarbon liquid/vapor characterization. Previous work has shown that pure alkanes, alkane mixtures, viscosity standards and stock tank crude oils have NMR relaxation times which vary linearly with viscosity/temperature and diffusivity on a log-log scale. However, pure methane at some temperatures and pressures does not follow the same trend. Thus, the linear correlation may not be valid for live crude oils that contain significant amount of methane. Therefore, the study of methane-hydrocarbon mixtures is of interest.

An NMR spectrometer equipped with a high-pressure probe was used to study the relationship between NMR T relaxation time and viscosity/temperature, diffusivity and gas/oil ratio of methane-hydrocarbon mixtures. Relaxation time and diffusivity measurements of three mixtures were made, methane-n-hexane, methane-n-decane and methane-n-hexadecane. It was found that unlike stock tank oil, relaxation times do not depend linearly on viscosity/temperature on a log-log scale. Each of the mixtures forms a different curve. Generalized correlations between viscosity, diffusivity, gas/oil ratio and NMR relaxation times were developed. First, the relaxation time mixing rule was developed by studying the theory of NMR relaxation mechanism. From the mixing rule, it was found that departure of relaxation times of methane-n-alkane mixtures from linear correlations on a log-log scale can be correlated with the proton fraction of methane, expressed as gas/oil ratio. Thus, correlations between relaxation time, viscosity/temperature and gas/oil ratio were developed. Correlations between relaxation time, diffusivity and gas/oil ratio were also developed. There is a linear relation between diffusivity and viscosity/temperature that is independent of composition. From these correlations, viscosity and gas/oil ratio can be estimated from NMR T1 relaxation time and diffusivity.
Viscous-Elastic Polymer Can Increase Microscale Displacement Efficiency in Cores
Authors: Wang Demin , Cheng Jiecheng , Yang Qingyan , Gong Wenchao , Li Qun
Published: December 2007

When flooding with viscous Polymers, due to the increase in viscosity and decrease in permeability (for polymers that absorb on the rock surface), the mobility ratio compared to water flooding becomes more favorable. Therefore the volumetric sweep efficiency increases and the recovery of the reservoir on a macro scale increases also.

Most people think that polymer flooding does not increase the recovery at a micro scale. But numerous results in this work do not support this conclusion. From cores in the lab, the effect of flooding with viscous-elastic polymers on different types of residual oil after water flooding was studied. The different types of residual oil are: 1) oil film on the rock surface; 2) oil in "dead ends"; 3) oil in pores throats retained by capillary forces; 4) oil un-swept in micro scale heterogeneous portions of the core. It could be seen that all types of micro-scale residual oil were reduced after flooding with viscous-elastic polymers.

Due to the elastic nature of the polymer, the velocity distribution in the pores are quite different from Newtonian Fluids and the polymer could also exert a very strong "pulling effect" on different types of residual oil. The study pointed out that the relationship between Capillary Number and Recovery of cores for Newtonian Fluids does not apply to fluids with elastic properties.

In the study, it was seen that the increase in micro scale recovery was related to the elastic properties of the polymer fluids. Different polymer fluids had quite different elastic properties. Some had practically no elasticity. Therefore, when selecting polymers for flooding, its elastic properties must be considered. The difference in incremental recovery can be more than 6 % OOIP (original oil in place), which is substantial, it can make a polymer flood successful (both technically and economically) or not.

The above conclusions can also be confirmed by pressure coring data and field results of large scale polymer (PAM) flooding in Daqing Oil Field, which is obtaining an incremental oil recovery of more than 13% OOIP. This magnitude of incremental oil recovery can not be explained by just an increase in volumetric sweep efficiency.

The above conclusions 1) can explain why some polymer floods were successful or not; 2) should be considered when selecting polymer floods and, 3) should be able to increase the incremental oil of future polymer floods.

The rheology of viscous-elastic fluids in porous media is very much different from fluids with no elasticity. Much work needs to be done in this field. Many conclusion obtained by studies on Newtonian Fluids need to be re-assessed when used on visco-elastic fluids.
Development of a New Sand Control Technique - Phase I: Laboratory Development
Authors: Aggour M. A. , Abu-Khamsin Sidqi A. , Osman E. A.
Published: December 2007

This paper presents the results of the laboratory development phase of a major project to develop a novel sand control technique that could overcome the technical and economic limitations associated with existing methods of sand control. The novel technique is based on in-situ sand consolidation by low-temperature oxidation of a hydrocarbon fluid that saturates the sand around the wellbore. Laboratory development consisted of two stages. In the first stage, the various process-controlling parameters were studied to determine the optimum conditions that yield consolidated sand with the highest possible compressive strength, minimum loss of permeability, and high stability against typical formation and workover fluids. Under the developed optimum consolidation conditions, it was possible to produce consolidated sand, from originally loose sand, that retained between 86.4% and 95.5% of its original permeability, was completely stable against flow of crude oil, water and mud acid, and had a compressive strength between 1,800 and 2,300 psi. In the second stage, the feasibility of field application of the process was demonstrated on a full-scale model resembling an 8-ft. section of a 7 in. cased well. The model was packed with loose sand and saturated with brine. The resulting consolidated sand around the casing was tested by flowing back at a rate of 44 bpd/ft. (the maximum available pump apacity) without any sand production. Plans are underway for the first field implementation of the process.
How the 3D Modeling Could Help Hole-Cleaning Optimization
Authors: King I. , Trenty L.
Published: December 2007

The development of complex wells with deviated and long horizontal sections induce hole cleaning and cuttings transport problems. A better knowledge of the mechanisms controlling the cutting evacuation is therefore necessary. This paper presents a three dimension numerical approach which has been developed to improve the understanding of the drilling mud flow behavior in the annulus. The influence of drilling parameters is pointed out. The way a settled cutting bed could modify the flow is also analysed. To go further in the drilling process modeling, cuttings have been introduced in the mud flow, with the same 3D approach. All this methodology allows to define critical drilling configurations for the cutting removal, and therefore will help to provide criteria for hole cleaning optimization.
Accounting for Seismic scale in Stochastic Reservoir Simulations Constrained by Seismic Data
Authors: Gilbert F. , Joseph C. H.
Published: December 2007

Integrating seismic data in 3D reservoir property simulations leads to more accurate reservoir models. But the difference of scale between both data should be taken into account. For that, seismic data are usually considered as 2D information, hence related to the vertically averaged reservoir property; this implies that the seismic scale (or resolution) is identified to the reservoir thickness, i.e. to some user-defined size independent of the actual seismic volume support. In this context, we propose a methodology which takes into account a more realistic 3D seismic volume support. This methodology calls first for the determination of the 3D volume support of the seismic data by looking at seismic variograms or at the seismic signal. Then, a two-step simulation methodology is applied. In Step 1, the reservoir property cube at seismic scale (i.e., on the seismic volume support) is estimated from the seismic data. In Step 2, the resulting estimated cube is used for constraining the Sequential Gaussian Simulation (SGS) of the reservoir property (at point scale) either through cokriging of data at different scales or through non stationary kriging. An application of this methodology is presented: porosities are simulated at one reservoir level, constrained by a 3D impedance cube after inversion. Results of both Step 2 alternatives are compared in terms of input reproduction, easiness of implementation, computing time, impact of the seismic data,…
Efficient Use of Streamline Simulation and Inversion Techniques to Improve Reservoir Modeling
Authors: Sarkar Amit K. , Faruqi Sohail A. , Barman I. , Wang M. K.
Published: December 2007

Benefits of a 4-step reservoir modeling process to properly manage highly uncertain permeability models are demonstrated. Streamline simulation generates results that compare reasonably well with conventional simulation results, but provides much greater speed.

Multiple permeability distributions were screened at the fine grid level using a streamline simulator, and improved further using an inversion simulator. The streamline simulator was also used during the upscaling process to screen the upscaled models. The resulting permeability model with lower uncertainty is more appropriate as input to conventional simulators for production data history matching, and forecasting.
Drilling Program Financing and the Operator Risk/Return Position
Authors: Batt Robert
Published: December 2007

Society of Petroleum Engineers 6200 North Central Expressway Dallas, Texas 75206

THIS PAPER IS SUBJECT TO CORRECTION

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

Introduction

The purpose of the drilling program is to raise venture capital for exploration and, to a lesser extent, development activities of petroleum producers. As a financing form, petroleum producers. As a financing form, although not entirely unique, it is particularly well adapted to the petroleum industry. The programs are able to capitalize on -the various features of the industry to provide an investment package that is attractive to (wealthy) outside investors.

Drilling programs are joint ventures, usually organized as limited partnerships, which permit petroleum operators and outside investors to participate in petroleum exploration and development. The operator assumes the role of general partner with the outside investors becoming limited partners. One feature of these programs is that they permit the pass-through to the outside investor of any tax benefits of the venture. Although this is the feature that receives the most attention, it is not the main purpose of these programs.

To the operator, the drilling program form of financing provides an additional degree of flexibility that is not available through more traditional financing sources. By taking advantage of this flexibility, the petroleum operator can not only obtain the needed financing, but can also receive other benefits.

Goals such as meeting current cash needs and providing continued support of the technical operations of the petroleum operator are also met by drilling programs. However, the target of this paper is to concentrate on the effects on the operator's risk/return position. It is aimed at showing how specific features of drilling programs provide the means of achieving satisfactory risk/return levels for the operator. It also is intended to point out particular risk/return characteristics that particular risk/return characteristics that would be unacceptable to the operator.

STANDARD FINANCIAL THEORY

Standard financial theory basically assumes that sources of funds employed by a firm can be classified as either equity or debt. Although this theory recognizes that variations of debt and equity exist, the analytical approach generally applied is to convert these "nonstandard" forms of financing into an equivalent debt or equity amount.

The use of fixed return securities, i.e., debt or its equivalent, results in the creation of "financial leverage." Just as a fulcrum is present when leverage is considered in present when leverage is considered in mechanics, the fulcrum involved with financial leverage is the fixed, after tax, payment required on these securities.
A Modeled Promotional Prospect for Devonian Shale Production
Authors: Plaster Jerry
Published: December 2007

A promotional possibility for a low producible but dependable gas reservoir such producible but dependable gas reservoir such as the Ohio shale is modeled and discussed. This involves the promotion of natural gas availability as part of a planned residential community cooperative. The requirements for success are outlined. Actual performance and return is not dependent upon the examples used. Other reservoirs and other areas can be applied to the model. Exploration, completion and servicing costs are included in the price of building sites and administered through a community cooperative. This affords the contractor a short term payout and long term operation through service contracts if desired. Drilling supplies may be on site or remote from the development. Storage, modes of investment, mechanics of a cooperative and a balance sheet example complete the discussion.

Introduction

Oilfield promotion has suffered recently in two ways, both of which tend to dry up investment money. First, the mistrust of the industry by investors and second, political interference. Combining investment political interference. Combining investment programs may be a solution-to free up capital programs may be a solution-to free up capital and increase domestic energy supplies by examining previously uneconomical gas reservoirs.

MODEL

The model for examination is a real estate development of new high quality homesites with cooperative ownership and operation of gas supplies included in the purchase price. This affords the homeowner purchase price. This affords the homeowner with a guaranteed supply of a presently preferred energy source and the investor with preferred energy source and the investor with a choice of short term return with gas exploration investment or long term in real estate building investment.

CRITICAL ASSUMPTIONS

To establish this working model a number of necessary assumptions must be made:The natural gas situation of limited availability and/or increasing price remains significantly unchanged, i.e., little or no possibility of massive new domestic supplies and/or a significant lowering of retail price.In the proposed area, the availability of over 100 acres at fair market price.
ERDA Research in Fracturing Technology
Authors: Komar C.A.
Published: December 2007

Research in fracturing technology for the ERDA organization is structured on (1) the development of new concepts for increasing the deliverability of natural gas from resources that are classified as marginal by present day practices and (2) the testing and transfer of practices and (2) the testing and transfer of new technology to the private sector. The program at the Morgantown Energy Research Center program at the Morgantown Energy Research Center is centered about their foremost expertise in delineating and utilizing natural and induced fracture systems for enhancement of resource recovery. More recently, the research program has been expanded to include studies of foam fracturing, production history from fractured wells, cost/effectiveness of stimulation treatments and fracture mechanics as support activities for field demonstration projects. The program at the Bartlesville Energy Research Center evolves about their broad experience in stimulation technology in the marginal gas resources of the western U.S. This experience includes nuclear, explosive and more recently, massive hydraulic fracturing stimulation technology.

The ERDA organization interfaces with industry in field demonstration projects of new stimulation concepts that are potentially attractive as techniques for improving the deliverability of gas from known marginal resources. The most widely tested concept to date is the development of massive hydraulic fracturing technology utilizing new fracturing fluids and large volumes of fluid and sand to create long propped fractures. A second noteworthy concept that merits consideration as a future demonstration project includes the utilization of natural and induced fracture systems in conjunction with slant hole drilling and multiple hydraulic fracturing. Together with explosive fracturing and recompletion technology, these concepts offer the best potential for increasing the natural gas supply.

Demonstrations of field worthy technology are conducted with direct service contracts or with cost sharing government-industry contracts both of which are approaches now being pursued. ERDA participation is to provide an interface for technical contributions to the efforts and for the transfer of new technology to be accomplished. Upon successful demonstration of new stimulation techniques, it is anticipated that rapid commercialization will follow.
Performance and Unitization of the Empire Abo Pool
Authors: Christianson S.Hugh
Published: December 2007

Voluntary Unitization of 97% of the Empire Abo Pool, Eddy County, New Mexico, went into effect October 1, 1973. A reservoir study had shown that Unitization would mean recovery of an added 30 million barrels of oil. This would result from aiding the natural gravity drainage by shutting in high gas-oil ratio wells and returning available plant residue gas to the secondary gas cap. A later study showed further improvement in rates and recoveries by drilling additional development wells in low gas-oil ratio areas. Continuing engineering analysis and an aggressive attitude by the Unit owners has resulted in substantial increases in oil recovery and productivity as compared to continuation of productivity as compared to continuation of competitive primary operations.

Introduction

The Empire field is located about eight miles southeast of the city of Artesia in Eddy County, New Mexico (Fig. 1). The discovery well for the Empire Abo reservoir was the Amoco-Hondo Oil Company - Malco "A" No. 1, completed at what is now the Unit M-14 location (Fig. 2), in November 1957. Development moved rapidly to the west, east, and north from the discovery, which proved to be only one location removed from the fore-reef edge of productive limits of the reservoir. Within three years some 215 of the eventual 250 producing wells had been completed. In defining producing wells had been completed. In defining the reservoir, 29 dry holes were also drilled. Field performance before and after unitization is shown in Figures 3 and 4.

Current pool producing rate for November 1976 is 41,700 BOPD, with the ARCO-Empire Abo Unit producing 41,062 BOPD of that total. Unit gas production in November was 55,746 MCFPD. Unit injection into the Abo gas cap in November was 34,451 MCFPD.

Atlantic Richfield Company, with 34.14% interest, operates the Unit for the 112 working interest owners.
The Physical Basis Of Darcy's Law And Its Importance In The Exploration And Production Of Petroleum
Authors: Hubbert M. King
Published: December 2007

The systematic application of fluid mechanics to the problem of extracting petroleum from underground reservoirs was begun during the decade of the 1920's, and soon thereafter the equation

(1)

which purported to describe the flow of any homogeneous fluid in a porous solid medium, and was attributed to the French engineer Henry Darcy, came into general use as the fundamental flow equation of the petroleum industry for underground fluids. This equation asserts unequivocally:that all fluids flow in a direction perpendicular to the surfaces of constant pressure and in the direction of pressure decrease,that in the same pressure field all homogeneous fluids would flow at each point in the same direction, andthat if the fluid is at rest—a special case of a fluid in motion— the fluid pressure in three-dimensional space must be constant.

However, the third of these propositions violates the known facts of hydrostatics; the second the known fact that diverse reservoir fluids, such as water, oil and gas, migrate in divergent directions and tend to become segregated; and the first can easily be violated experimentally in any desired manner. Hence, the use of this equation in reservoir engineering can hardly have produced any but inhibitory effects in the attempts to understand what really occurs during the exploitation of a petroleum reservoir.

Returning to first principles, and incidentally to the original Darcy experiment, one finds that the flow of a homogeneous fluid through an isotropicporous solid can be described by the equation

(2)

in which is the volume of the fluid crossing unit area normal to the flow-lines in unit time, E is the force per unit mass exerted by the environment on an element of the fluid at a given point, and sigma is a fluid conductivity parameter.

Further examination shows that

(3)

and hence is the vector sum of two separate forces per unit mass, one due to gravity and the other to the gradient of the pressure. In general, these have independent directions. Also,

(4)