bluuebunny/crossref_metadata_2025 huggingface dataset:
A New Approach to Parameter Estimation in Well Testing
Authors: Padmanabhan L. , Woo P.T.
Published: December 2007

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

Introduction

Although computer solution technique are used universally in reservoir simulation and history matching problems, in the context of well testing one finds an almost exclusive reliance on the conventional graphical techniques (build-up and drawdown plots and type curves). While these graphical methods have been remarkably successful in providing quick answers and valuable providing quick answers and valuable insight into the reservoir structure, they are somewhat limited in scope and impose some strong restrictions on the test schedule. The practical difficulties in applying these methods are that the assumptions on which they are based do not often hold, the flow rates are variable or even unknown during certain phases of the test and finally the estimates of the parameters obtained from different methods may vary widely. It is true that the Horner-buildup and drawndown analyses can be extended to accommodate variable flow rates by a judicious application of the superposition principle to asymptotic analytical solutions [Ridley]; however, the information that can be derived pertaining to the damage near the wellbore is far from complete or accurate. Indeed all that can be inferred about well-damage is in terms of a skin factor and not whether this "skin" is really due to a plugging of the perforations or due to plugging of the perforations or due to mud invasion into the formation and how far into the formation that the damage persists. None of these methods operate satisfactorly if flow data are missing; moreover the assumption of a constant flow rate in place of missing information on flow rate may in fact lead to misleading results. If one has to use type curves, the results are often ambiguous as they are based on very subjective judgements on what is or is not a matching overlay between data and the type curve. In spite of the existence of myriads of such methods, when it comes to the simultaneous estimation of several reservoir parameters, both local and far from parameters, both local and far from the well, there is no unifying procedure that produces a unique answer. This stems partially from the fact that most of these methods are based on the long-time asymptotic solutions of the radial flow equation.
Experimental and Calculated Relative Permeability Data for Systems Containing Tension Additives
Authors: Talash A.W.
Published: December 2007

Experimental and Calculated Relative Permeability Data for Systems Containing Permeability Data for Systems Containing Tension Additives

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

This paper was prepared for the Improved Oil Recovery Symposium of the Society of Petroleum Engineers of AIME, to be held in Tulsa, Okla., March 22–24, 1976. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and with the paper, may be considered for publication in one of the two SPE magazines.

In order to predict recoveries for low tension waterfloods, one must have information on the relative permeabilities of oil and water under conditions approaching miscibility. In this study relative permeability data were obtained by two conventional methods, the displacement method and the steady-state method, in fired Berea cores for a crude oil-water system containing tension reducing additives (surfactants). Four surfactants were utilized, two being preferentially water-soluble and the other two being preferentially oil-soluble but not to the same degree. From the measured data, equations were developed for calculating relative permeability data for the systems examined. As a test, the equations developed were utilized in a one-dimensional reservoir simulator program for computing laboratory waterflood performance. The comparison given in the paper shows that the calculated values were in good agreement with the measured results.

Introduction

In order to mathematically simulate laboratory waterfloods one must have accurate relative permeability data. These data are usually obtained in one of several ways, namely,Direct MethodsSteady-StateDisplacementStationary-PhaseNuclear Magnetic ResonanceIndirect Methods (by calculation, using proven equations)Naar-Wygal EquationsLand Equations

The direct methods, as listed above, are much preferred over the indirect methods; however, a complete set of relative permeability data is rarely found.
An Experimental Study of Acid Placement in Variable Inclination Laterals
Authors: Zhu D. , Hansen A. , Bruksas R. , Hill A. D.
Published: December 2007

Acidizing a horizontal well is more complicated and difficult than acidizing a vertical well. The fluid distribution in a horizontal well is affected by a longer wellbore length, a broader variation in the reservoir properties along the wellbore, and possibly different mechanical means to place the fluids in the wellbore. Since a nominally horizontal is not perfectly horizontal, the wellbore trajectory may have numerous upward and downward inclined sections. This allows the injected fluid to under-ride or over-ride the resident fluid. Gravity effects could result in acids (often a denser fluid than the resident fluids in the wellbore) preferentially treating the low spot in such a well.

We have conducted several experiments to study the effect of gravity on acid placement in horizontal wells. The experimental apparatus contains two pipe segments with adjustable inclination to simulate a high spot (crest) or a low spot (trough) in a nominally horizontal well. The experimental results were used to characterize fluid placement in horizontal well acidizing, and to verify a mathematical model developed previously1,2.

We observed from the experiments that in both trough and crest cases, gravity under-riding influences the acid placement along the wellbore significantly. The comparison of the experimental results with the simulation result from the mathematical model developed before shows good agreement, and therefore validates the mathematical model.
Carbonate Matrix Acidizing with Acetic Acid
Authors: Huang T. , Ostensen L. , Hill A. D.
Published: December 2007

Conventional matrix acidizing in carbonate reservoirs uses hydrochloric acid to remove formation damage and stimulate well performance. Many experimental and theoretical studies in carbonate acidizing have confirmed the existence of an optimal acid injection rate at which major wormholes are formed, and the benefit from stimulation is maximized. This optimal rate depends on reservoir conditions, rock properties and chemical reaction rate. At high reservoir temperature, the optimal rate of hydrochloric acid is usually too high, and it sometimes is beyond the maximum injection allowed (the rate to avoid fracturing formation). In this case, weak acids, such as acetic acid, are alternative fluids to stimulate the wells. In our previous study, a theoretical model showed that under the same condition, the optimal injection rate for weak acids is relatively lower than the one for strong acids.

This paper presents an experimental study of the wormholing process in carbonate acidizing with acetic acid. Carbonate rock samples were acidized, and the effectiveness of the process and the optimal injection rate were studied by measuring the acid volume needed to propagate wormholes through the cores and by making castings of the wormhole structures after acidizing. The experimental results from this study confirmed that the optimal injection rate of acetic acid is lower than the optimal rate for hydrochloric acid. It also showed from the castings that the radius of wormholes created by acetic acid at the optimal rate is larger than that created by hydrochloric acid at the optimal rate. We then demonstrate how these results can be used to determine the optimal acid system and injection schedule for field application.
The Nature of the Compacted Zone Around Perforation Tunnels
Authors: Arora Devinder S. , Sharma Mukul M.
Published: December 2007

The creation of perforation tunnels through the use of shaped charges is often found to leave a zone of compacted rock of low permeability around the tunnel. The low permeability of this compacted zone is a result of grain crushing and fines accumulation. Laboratory experiments reported earlier indicate that the distribution of fines and the permeability around the perforation depend on several factors including underbalance pressure, rock strength and fluid properties.

In the present work, a model has been developed to understand the factors controlling the permeability distribution around a perforation tunnel. During underbalance perforating, the permeability of the region around the perforation is controlled by fines generated by the shock wave and by fines entrained during surge flowback into the wellbore. Surge flow around the perforation tunnel determines the radius of the tunnel formed as well as the cleanup of fine-grained material near the face of the perforation. Fines are mobilized around the perforation tunnel wherever the surge velocities exceed a critical velocity. Some of the mobilized fines are trapped at pore throats near the tunnel giving rise to the crushed zone while those very close to the tunnel (~0.5 cm) are produced. The crushed zone thickness is found to increase with rock tensile strength, fines content and fluid viscosity. The model also clearly shows why a lower optimum underbalance pressure is required for higher permeability rock. Results from the model are compared with experimental data on fines content and permeability around a single perforation. Good agreement is obtained with lab and field observations as the key parameters (rock permeability and underbalance pressure) are varied for both gas and oil wells.
OCCAM: Onset-Constrained Colloidal Asphaltene Model
Authors: Correra Sebastiano , Donaggio Francesca
Published: December 2007

Asphaltene deposits affect the primary production of oil from the wellbore to the surface facilities and may also cause problems during storage and pipeline transportation. A model to predict the occurrence of asphaltene separation is therefore required in order to avoid or minimize upsets due to asphaltene precipitation.

With the aim of identifying the physical nature of the asphaltene separation, both onset-of-precipitation and quantity-of-asphaltene experimental data were produced. While in general previous researchers have tried to apply or adapt well-known models to describe the experimental results, the peculiar behavior observed for asphaltenes has been used here to gain insight into the mechanism of precipitation. From this work a model (Onset-Constrained Colloidal Asphaltene Model) has been developed, allowing predictions of asphaltene flocculation from standard PVT data and a limited set of experimental data on stabilized oil. Because it is physically well founded, the model is applicable to any situation in which asphaltene separation is possible; it allows prediction of both the precipitation onset and the quantity of asphaltene that separates as a function of oil composition, temperature and pressure.

Model applications show good agreement between predicted and experimental data on stock tank oils; moreover upstream applications are shown which further confirm model results. Besides, the model explains numerous experimental observations and physical descriptions of many other researchers, so that it is further reinforced by the prior literature.

A new insight into the phenomenon of asphaltene precipitation was gained and an original model was built, so that most of previous experimental data can be included in this framework.
How Effective is Underbalanced Drilling at Preventing Formation Damage?
Authors: Santos Helio , Queiroz J.
Published: December 2007

A series of return permeability tests with foam has been conducted to evaluate the potential formation damage while drilling underbalanced (UBD). The tests were conducted with overbalanced pressure, simulating the conditions when killing the well is necessary to perform some operations while drilling. The results indicated significant permeability reduction, even when just water was used as drilling fluid. A deep study was then conducted to investigate the potential causes of the damages and to define the best way to remedy this problem.

The results obtained from the laboratory investigation show a need for the industry to better plan UBD operations to avoid undesired permeability reductions. Discussion of some damage mechanisms accepted today is presented, as well as some suggestions to extract the most out of a UBD job. According to the results it is essential to develop ways to have an underbalanced condition at all times while drilling. Even completion should be planned to be conducted without exposing the formation to overbalanced pressure. It is extremely important to pay attention to the periods during which the formation is exposed to an overbalanced condition, and try to avoid them as much as possible.
Successful Application of Oil-Based Drilling Fluids in Subsea Horizontal, Gravel-Packed Wells in West Africa
Authors: Chambers Mike R. , Hebert Darrell B. , Shuchart Chris E.
Published: December 2007

A new approach to drilling and completing long horizontal open-hole gravel packed intervals in a subsea West African Field development using oil-based drilling fluid throughout the well trajectory has resulted in significant cost savings and increased well productivity. Without this successful change and the use of horizontal wells, many of the subsea wells drilled in 50’- 2200’ of water would have been uneconomical.

Previously, the upper, non-pay portions of the subsea wells were drilled with oil-based drilling fluids while the horizontal reservoir sections were drilled with a sized calcium carbonate-polymer drill-in fluid. To remove filter cake damage following gravel packing, acidization of the entire horizontal interval was required. Operations associated with changing the drill-in fluid and acidizing added significant cost and complexity to well completions. In addition to higher completion costs, the water-based drill-in fluid reduced drilling flexibility in the target channel sands resulting in more sidetracks and in some cases less than optimal completed intervals. It was recognized that continued use of oil-based fluids through the reservoir section would overcome these limitations, however, the damage potential of using oil-based drilling fluids prior to gravel packing was unknown.

This paper presents the development, application, and results of the new drilling and completion practice for horizontal, gravel-packed, oil wells offshore West Africa. Large and small scale laboratory testing will be described, including formation damage core testing, development of displacement and cleanup procedures and fluid compatibility. Integration of technical advisors, laboratory personnel, and field operations led to rapid implementation of the new technologies. A pilot hole test was conducted in the field followed by successful application in three wells. The new procedures have resulted in improved drilling, considerable cost savings, and observed PI’s 2–3 times higher than similar wells using water-based drill-in fluids.
Formation Damage Abatement: A Quarter-Century Perspective
Authors: Ghalambor Ali , Economides M. J.
Published: December 2007

Petroleum well production impairment has long been associated with formation damage. Concepts such as the skin effect and its various manifestations have been introduced to account for the effects of damage. The origins of damage and the types of damage have also been the subjects of intense scrutiny. Abatement has included preventive measures such as the use of "non-damaging" fluids, presumably more benign processes, and improved drilling and well construction procedures and techniques. Once in place, the removal of damage has spawned an entire industry, that of matrix stimulation. This involves the use of appropriate remediation fluids, complete with the understanding of the often contrasting interaction among these fluids, the fluids and the damage, and very importantly, the side-effects which can damage the well more than its pre-stimulation state. Again, appropriate hardware was necessary. Due to the fact that damage removal is often either incomplete or unsuccessful, methods of by-passing the damage, such as high permeability fracturing, have been developed. Finally, brute force approaches are common, including the drilling of more vertical and/or horizontal wells regardless of the damage in order to get enough production. This paper is a critical review of both the evolution of the technologies and the thinking processes that have permeated the industry over the past quarter century. Particular emphasis is given to the resolution of controversial subjects and their impact on the field.

These include issues such as matrix stimulation versus fracturing, sand production control versus sand de-consolidation management, underbalance versus extreme overbalance, perforating and drilling fluids and practices.
Monitoring the Solids in Well Streams of Underground Gas Storage Facilities
Authors: Megyery M. , Miklós T. , Segesdi J. , Tóth Z.
Published: December 2007

Abstracts

In Hungary, underground gas storage (UGS) projects have been launched in depleted natural gas reservoirs. Sand only appeared in the well streams after the eighth year of operating the gravel packed and sand-filtered UGS facilities. In order to prevent from surface and down-hole failures, sand-detecting apparatus working on erosion basis was mounted onto the wells. In the detector the well stream is directed through a properly shaped obstructer to a tubular probe. Sand-free well stream does not erode the probe, appearing solids, however puncture it and this can be detected. The equipment is calibrated on each well by solids having the same characteristic grain size and material as those in the reservoir.
New Device for Rheology Measurements of Proppant-Laden Fluids with the Fann 50 Viscometer
Authors: Thesing A.
Published: December 2007

The Fann 50 and equivalent viscometers are widely used in determining fracturing-fluid rheologies. Unfortunately, the standard couette-type configuration for the Fann 50 viscometer cannot measure the rheology of a fluid accurately if the fluid contains proppant. The alternative techniques currently used to circumvent this limitation can produce misleading results. This paper discusses the design and operation of a new helical screw (HS) bob that allows researchers to measure the rheology of proppant-laden fluids accurately.

The HS bob produces crucial information about the interaction of proppants with fluids used during hydraulic fracturing operations. The HS bob was successfully modeled as a straight bob, allowing accurate calculation of rheological parameters. The technique gives engineers good insight into the way a hydraulic fracturing fluid transports and supports proppant (especially resin-coated proppants, or RCP–s) into a created fracture.

Because the HS bob keeps the proppant mixed with the fluid during tests, it prevents the formation of a consolidated proppant plug at the bottom of the test cup, as can occur when the proppant is resin-coated (RC). This paper presents examples of interactions between different kinds of crosslinked fracturing fluids and RCP–s and compares these techniques with the standard technique in which resin water is used.

The HS bob for the Fann 50 viscometer is shown to be useful for studying the real-time interaction between RCP–s and hydraulic fracturing fluids.
How Minifracs Alter Leakoff and Ways to Counteract It
Authors: Smith Jeff , Vitthal Sanjay , McGowen James M. , Dusterhoft Ron
Published: December 2007

The analysis of minifracs in high-permeability formations has been the subject of several studies and debates. In many cases, the leakoff from the frac-pack appears to be less than that from the minifrac, which is normally conducted before the frac-pack. Consequently, the net pressure rise observed is less than the predicted net pressure based on the minifrac analysis. Rules of thumb have been developed to account for this apparent change in leakoff behavior. These rules include adjusting the spurt loss, choosing a latter-time closure pressure based on previous experience, and adjusting the observed fluid efficiency by an arbitrary factor. This paper attempts to provide a rationale for explaining the discrepancy between leakoff data collected from minifrac analysis and the observed frac-pack behavior. This paper also presents the results of laboratory experiments and field tests that show that the injection of a minifrac alters the observed fluid efficiency. Laboratory tests evaluated the magnitude and character of the fluid loss from subsequent injections of a frac-pack fluid. These tests were conducted with cores ranging from 100- to 3000-md permeability. Field results from trials in which two minifracs were injected in the same zone are also presented. These field data are from wells in the Gulf of Mexico (GOM) and from a well in North Africa, all of which experience high fluid-leakoff rates. The results from these injections show that the effects of minifrac fluid can alter fluid efficiency significantly. Finally, the paper proposes methods and best practices for measuring or counteracting this effect by altering the sequence of injections into the formation. Laboratory data supports the philosophy behind these best practices.

In addition, field data illustrate the success of this altered injection schedule.
A Prelude to Formation Damage Prevention–Achieving a Reliable Primary Cement Job
Authors: Ghalambor Ali , Mikolajczyk Ray , Revett Lowell W.
Published: December 2007

Formation damage does not begin or end at total depth of the wellbore, even though all probable causes have been eliminated or practiced. A poor primary cement job is a major contributing factor to formation damage scenarios. Formation damage in many instances ends with a 360-degree circumferential cement bondage between the wellbore producing formation and the outside diameter of the casing. Ideally, a good primary cement job integrates the productive formation to the casing. The normal correction for the poor primary cement job is the secondary cement job–a cement squeeze. The cement squeeze can cause its own problems, such as destroying permeability and productivity of the well. The solution for getting a good circumferential cement job is to acquire proper casing/wellbore standoff with centralizers made for the conditions. Without proper casing/wellbore standoff, the fluids (mud, mud flush, and cements) cannot flow upwards completely around the casing. Most poor primary cement jobs are directly attributed to poor casing/wellbore standoff (poor centralized casing). Many of the problems that plague oil companies can be traced to less than adequate cement jobs. Sometimes these problems take years to manifest themselves, other times they may never be recognized. These problems include unexplained changes in the production rates of wells and/or the watering out of up-structure wells. If these problems are not correctly identified, productive zones may be abandoned or bypassed. Also, maps are sometime incorrectly redrawn to reflect the observed production. In this paper, available technology with case histories will be presented to document and illustrate the results of proper casing/wellbore standoff and its implications to formation damage/production impairment. It will demonstrate the proper procedure and centralizations for various formation characteristics. Situations that can result from communication in the casing annulus and the importance of their early detection are reviewed. Techniques that can be used to reduce the probability of leaks in new wells and methods of detecting leaks in existing wells are also discussed.
A Multi-Zone Single-Trip Gravel Packing and Production Technique Reduces Completion Costs by 60% Compared to Conventional Water-Packing in a Single-Selective Completion in the Gulf of Mexico
Authors: Rivas L. F. , Zeiler C. E. , Graff B. , Ogbunuju E. , Parlar M.
Published: December 2007

Single selective gravel pack completions can be very expensive in offshore environment due to high rig costs. Conventional techniques for such completions involve multiple trips in and out of the hole. A typical procedure consists of the following 6.5 round-trips excluding a wire-line trip to set the sump packer: (1) Perforate the lower zone, (2) Gravel pack the lower zone, (3) Run and set the packer plug to isolate the lower zone, (4) Perforate the upper zone, (5) Retrieve the packer plug, (6) Gravel pack the upper zone, with a GP assembly that includes an isolation assembly for lower zone, and (7) Run the production tubing. This process typically takes 8–10 days, prohibiting the completion of zones with marginal economics.

In this paper, we present a new technique used for a single selective gravel pack completion in the Gulf of Mexico. Because the two zones were separated by a long (210-ft) shale section and because sufficient rat hole was not available, one trip perforating and packing technique could not be used. Furthermore, the marginal lower zone would be uneconomic both with the conventional water packing technique and without sand control, the latter due to uneconomic production rates required for sand-free production. The proposed technique involved perforating of both zones in one trip, and subsequently gravel packing both zones simultaneously through the production tubing with shunt tubes bypassing the isolation packer between the two zones. The production rates from the lower zone have been stable at 10 MMSCFD (an order of magnitude higher than the predicted sand-free production rate without any sand control) with an associated condensate production of 200 BPD. The whole operation required only 66 hrs of rig time, resulting in 60% savings to the operator compared to conventional water packing of both zones separately, and making the economic completion of the lower zone possible. The details of the field procedures along with an analysis of the production data and an economic comparison to the alternatives are presented.
Oil-Based Muds for Reservoir Drilling: their Performance and Cleanup Characteristics
Authors: Davison J. M. , Jones M. , Shuchart C. E. , Gerard C.
Published: December 2007

The increased inflow area offered by horizontal wellbores, and hence the greater productivity potentially available, has led to an increase in the drilling and completing of such wellbores. The correct engineering of the reservoir drilling fluid is critical to achieving the ulitmate aim of minimising skin for the completed interval.

This paper evaluates the performance of a standard OBM to drill such wellbores, concentrating on its formation damage characteristics and the flow initiation pressures (FIP) required for production to flow through the filtercake. For heterogeneous reservoirs, we show that in low permeability rocks the damage is relatively low but the FIP high. Conversely, for high permeability rocks the FIP is low but formation damage relatively high. If the drawdown pressure available from the reservoir is low, then we have the scenario where inflow will occur predominantly from the higher permeability formations which could be badly damaged but little inflow will occur from the relatively undamaged lower permebility rocks. In terms of maximising production, this is obviously a less than optimal scenario.

With this in mind, evaluations were conducted of cleanup fluids to gauge their effect on lowering the FIP of the OBM filtercakes. Various fluids were screened for their mud removal performance which would potentially indicate good OBM ‘chemical breakers’. Mud parameters such as oil:water ratio, base oil type and emulsifier content all affected the efficiency of the cleanup fluids. The best cleanup fluids were then utilised in a series of core tests to evaluate their effectiveness in reducing the filtercake FIP. Reductions of between 25–40% were possible, although parameters such as soak time and overbalance pressure were critical to their success.
Experimental Investigation of the Effect of Drilling-Fluids/Clay-Minerals Interaction on Resistivity, Acoustic velocity, and Log-Derived Porosity
Authors: Liu Xiangjun , Luo Pingya , Cheng Yijian
Published: December 2007

Physical and chemical interactions do occur between clay minerals and drilling fluids. The interactions will result in permeability and porosity decrease in reservoir formations. We especially want to know what happened in the formation after drilling. In the process of studying formation damage, well log information is practicable and important. Well logging is done after drilling, so well log information contain a lot of knowledge related with the interaction between drilling fluids and clay minerals. In order to study the effect of drilling fluids/clay minerals interaction on formation permeability and use well log information to evaluate formation damage quantitatively after drilling, an apparatus which can measure resistivity, acoustic velocity, core deformation and pressure change along the length of the sample simultaneously under conditions of elevated temperature and pressure is developed. Experiment were done on artificial shale samples, natural shale samples and shaly sand samples utilizing different aqueous solutions at temperatures ranging from 25°C to 60°C and pressures ranging from 2.5Mpa to 12Mpa. In the shale formation, the changes in resistivity and acoustic velocity are always corresponding to the shale deformation. In the permeable shaly sand formation, the incompatibility between formation water and drilling fluid is the one of reason that result in drilling fluid filtrate invasion. Using these data, the model that describe the relationship between resistivity and contacting fluid properties, interaction time between formation and drilling fluid, permeability and acoustic velocity derived porosity is obtained. The model predictions agreed with the experiment. Well log information is abundant and low cost relative to sampling, so this study is useful for improving understanding of formation damage.
A Review of Gas Fracturing Technology
Authors: Li Wenkui , Xue Zhongtian
Published: December 2007

Gas Fracturing, an oil/gas well stimulation technology by means of powder and/or propellant inflamming in wells to create multiple radial fractures in the vicinity of well-bore and hence to enhance the well production, has been widely studied, tested and applied both home and abroad, and shown a bright prospect in oil and gas industry. The emerging technology for stimulation of oil/gas wells·Gas Fracturing can rapidly generate a high pressure gas pulse. This pulse of gas causes the rock to fracture and produces multiple, short(5¢:i20 ft.) fractures, radiating from the well-bore; Another benefit of Gas Fracturing is the reduction in pressure drop at the well-bore which can reduce solids dropping out of the flowing phase into the pore spaces(e.g.: paraffin, scale, etc.). This paper summarizes the achievements of our effort on research and application of the technology. In theory, we will describe the acting mechanism, the forming fractures mechanism and stimulation mechanism of Gas Fracturing. Laboratory results and field evidence will be presented to validate those theory. Application of the Gas Fracturing technique will be outlined. It will refer to many aspects, such as exploration, production, injection and ultra-deep wells.
Gas Injection as a Method for Improved Recovery in Gas-Condensate Reservoirs with Active Support
Authors: Cruz Lopez José Alejandro
Published: December 2007

One of the greatest problems currently in the oil industry is the difficulty for reaching a high hydrocarbon recovery in gas-condensate fields, the main problem being the pressure and the presence of active aquifer in such reservoirs.

When a reservoir lacks active aquifer their recovery are very low of the order of 20 to 30 % for condensates and between 70 to 80 % for the gas.

In reservoirs with active aquifers, their recovery factors are greater, of the order of 50% in condensates and about 70% for gas; however, a severe water invasion exists in the productive areas leaving about 40% of trapped hydrocarbons.

The present paper describes a technical study for the implementation of recovery methods improved with gases, and the different factors of hydrocarbon recovery factors obtained using different gases such as dry gas, CO2, nitrogen, flue-gas and other feasible combinations of injection gases

The best method obtained in such study consists on the injection of a dry gas in the zone of interest very near the water front, in order to avoid the entry of the water to the well and to recede the level of the current water in the perforations with high water cut, thus recovering trapped hydrocarbons, therefore obtaining high recovery factors of the order of 70 to 90 % of the original volume.
New Formulation for Formation Resistivity Factors of Fractured Porous Media
Authors: Pérez-Rosales C. , Cruz-Hernández J. , Islas-Juárez R. , Mercado-Díaz A.
Published: December 2007

A new formulation for determining formation resistivity factors of fractured porous media is presented. For establishing the mathematical model, a fractured medium is idealized as a cubic arrangement of cubic matrix blocks (Warren and Root model). Experimental results which validate the new formulation are given. The work is aimed at obtaining a reliable tool to aid in the interpretation of electric well logs of naturally fractured reservoirs.
Comparison of Numerical Simulations and Laboratory Waterfloods with In-Situ Saturation Imaging of Fractured Blocks of Reservoir Rocks at Different Wettabilities
Authors: Graue A. , Moe R. , Baldwin B. A.
Published: December 2007

Iterative comparison between experiments and numerical simulation has been used to predict oil recovery mechanisms in fractured chalk as a function of wettability. Selective alteration of wettability, by aging in crude oil at elevated temperature, produced chalk blocks which were strongly-water-wet and moderately-water-wet, but with similar pore geometry and mineralogy. Larger scale, nuclear-tracer, 2D-imaging experiments monitored fluid distributions while waterflooding blocks of chalk, first whole then fractured. This data provided in-situ fluid saturation development for validating numerical simulation and evaluating capillary pressure- and relative permeability input data used in the simulations. Capillary pressure and relative permeability at each given wettability were experimentally measured and used as input for the simulations. Optimization of either Pc-data or kr-curves gave indications of which of these input data could be more trusted. History matching both the production profile and the in-situ saturation distribution development gave higher confidence in the simulation. Labelling the injection water differently from the in-situ water made it possible to determine the degree of water mixing during the waterfloods. Mixing of injection water and in-situ water during waterfloodng was determined for both unfractured and fractured blocks. Reduced water wettability resulted in less oil recovery by spontaneous imbibition. Interconnected fractures did not significantly impact the final oil production when the permeability increase after fracturing was low, for both strongly-water-wet and moderately-water-wet conditions. However, in-situ saturation distributions were significantly affected by the wettability conditions. For higher permeability increase after fracturing significant reduction in oil recovery was experienced at less water wet conditions, while oil recovery at strongly-water-wet conditions was not reduced, even at high permeability increase after fracturing. The overall best match between the simulations and the experiments was obtained using the experimentally obtained capillary pressure curves and optimizing the experimentally measured relative permeabilities.
Implementing Convection in a Reservoir Simulator: A Key Feature in Adequately Modeling the Exploitation of the Cantarell Complex
Authors: Manceau E. , Delamaide E. , Sabathier J. C. , Jullian S. , Kalaydjian F. , De Guevara J. E. Ladron , Bujanos J. M. Sanchez , Rodriguez F. D.
Published: December 2007

As for some thick and highly fractured Iranian fields, the Cantarell complex located offshore Mexico presents features (decrease in the production GOR and bubble point pressure with time) that reveal the effect of convection.

This effect on the past homogenization of the fluid properties is discussed and is supported by a thorough characterization of the thermodynamic properties of the actual reservoir fluids.

In order to model convection, the reservoir simulator used for this study was adapted on purpose. Sensitivity runs were performed to demonstrate the necessity of accounting for convection for matching the past history of the Akal field, part of the Cantarell complex.
Drilling and Completion Strategies in Naturally Fractured Reservoirs
Authors: Ehlig-Economides C. A. , Taha Mohamed , Marin H. D. , Novoa Enrique , Sanchez O.
Published: December 2007

Traditional exploration drilling practices include targeting the structural crest; maintaining a vertical borehole; and drilling over-balanced for safety reasons. All three drilling practices may threaten success in naturally fractured reservoirs in which well and reservoir flow performance relies on flow through natural fractures. Depending on the deformation mechanism of folds, more folding related natural fractures may develop on the limb of the structure than on the crest. At typical depths, open fractures planes are likely to have a subvertical orientation; and a deviated borehole, drilled in a direction normal to the natural fractures, will intersect many more fractures than a vertical one. Over-balanced drilling can result in lost circulation of damaging drilling fluids and solids in the natural fractures. Cementing the fractured zones can further plug natural fractures, leaving little behind pipe to provide sought-after productivity from the natural fractures. This paper offers insight on drilling and completion strategies based on experiences in two South American locations with distinct structural styles. One is a Devonian gas discovery in Bolivia and the other a block southwest of Lake Maracaibo with both mature fields and exploration prospects of Cretaceous age. In both instances, the structural style and orientation provide a framework for borehole trajectory planning.
Introduction To Carbon Logging
Authors: McWhirter Vernie C.
Published: December 2007

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

This paper was prepared for the Improved Oil Recovery Symposium of the Society of Petroleum Engineers of AIME, to be held in Tulsa, Okla., March 22–24, 1976. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and with the paper, may be considered for publication in one of the two SPE magazines.

A nuclear logging method to determine the presence of hydrocarbons behind casing regardless of water salinity has been developed.

This log, referred to (is the Carbon Log or Carbon/Oxygen Ratio Log, is commercially available on a limited basis in the United States and Canada..

For most of us in the oil production industry, the Carbon Log principle, including the technique, terminology and method of operation, is new. This paper is written and presented for those who desire an introduction to Carbon Logging.

The intent of this paper is to cover the basic nuclear principles involved, instrument operation and how use is made of the nuclear reactions.

Examples of interpretation techniques for the determination of oil saturation, lithology, salinity and the presence of gas are shown.

Introduction

The nuclear reactions from which the Carbon Log measurements are obtained are not new. Reactions that occur when certain elements are bombarded with high energy neutrons are well documented.

Fortunately, a number of the elements that are present in the rock matrix and the fluid contained therein do react in some identifiable way to neutron bombardment.

The Carbon Log is made possible due to the fact that Dresser Atlas has a monoenergetic neutron source that can be controled so as to provide a desired amount of neutrons in periodic bursts, i.e. the neutrons produced are of one specific energy level---14.2MEV.
Application And Selection Of Electric Submergible Pumps
Authors: O'Neil Richard K.
Published: December 2007

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

This paper was prepared for the Improved Oil Recovery Symposium of the Society of Petroleum Engineers of AIME, to be held in Tulsa, Okla., March 22–24, 1976. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and with the paper, may be considered for publication in one of the two SPE magazines.

Introduction

This paper reviews the application of electric submergible pumping systems to oil field pumping requirements. Also presented is a typical pump and motor design procedure and a review of operating parameters that can affect pump performance.

DESCRIPTION OF EQUIPMENT

The submergible pumping system's major components are motor, protector, pump and cable which are run into the well on tubing. Surface components are the cable junction box, switchboard and transformers. Figure 1 shows the downhole equipment.

Motor

The submergible electric motor is a 3-phase, induction type, that is oil-filled for cooling and lubrication. A high starting torque enables it to reach full load operating speed of approximately 3500 RPM in less than fifteen cycles, thus reducing drag on the power supply. Cooling is achieved by heat transfer to the well fluid moving by the motor. For this reason, the unit is set above the producing zone. Submergible motors have been successfully operated in ambient temperatures in excess of 300 deg.. These motors are available in a range of diameters, horsepowers and voltages to accommodate a wide variety of applications.
Preventive Maintenance for Beam Pumping Equipment
Authors: Bullard Denny B.
Published: December 2007

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

This paper was prepared for the Improved Oil Recovery Symposium of the Society of Petroleum Engineers of AIME, to be held in Tulsa, Okla., March 22–24, 1976. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and with the paper, may be considered for publication in one of the two SPE magazines.

Introduction

A preventive maintenance (PM) program has been established in the southeastern New Mexico portion of Continental Oil Co.'s production department operation. The PM system has been in operation for 12 months and covers over 2,000 separate pieces of major surface equipment.

The concept of preventive maintenance is not new in production operations; however, most operating organizations incorporate PM and operations in one organization. The primary disadvantage of this type of set-up is the secondary priority PM receives. Day-today operating problems normally receive first priority and PM work is done after "emergencies" are handled. For that reason, Conoco's "PM" organization has been separated from the "operations" organization.

Preventive maintenance is the systematic inspection, cleaning, lubrication, and servicing of equipment. The objective of PM is to prevent malfunctions and breakdowns, with the result that all mechanical equipment will work as well and as long as it should with minimum repairs.

Operations include those tasks that have to be done to efficiently produce oil and gas wells, to monitor and control oil-field facilities, to answer alarms, and to assure that environmental and safety standards are maintained. An efficient production operation must give equal priority to operational tasks and PM.

This paper deals only with the PM for beam pumping equipment. However, the procedures followed in establishing the PM for the beam pumping equipment are essentially the same for all pieces of equipment included in this project.

PM ORGANIZATION

The PM work for all of the equipment covered is under the direction of a PM foreman. Four two-man crews and a test engineer are assigned to the PM production foreman. Two of these crews handle PM on waterflood equipment; one crew is assigned tank battery equipment; and pumping units are serviced by the fourth two-man team. The test engineer uses specialty test equipment such as vibration analyzers on all equipment in the field.

Each PM team also handles "breakdown" repair work to the equipment assigned to them.
Deepwater Riser Management
Authors: Cummins I , Neme E , Todd W
Published: December 2007

This paper discusses how it is both cost effective and operationally practical to use a fitness for purpose approach to riser inspection scheduling instead of a technique based on accumulated fatigue damage within each riser joint. At the same time, the inherent scheduling uncertainties are reduced.

The riser monitoring that is necessary for successful operation of a deepwater riser and for inspection scheduling is also outlined. A calibration technique is evolved for the predicted riser inspection scheduling and safety is improved by providing early warning of an accumulation of unexpectedly high fatigue damage with an effective monitoring system.

Significant time and cost savings can be made while maintaining high levels of safety with these practical solutions, which could contribute to the development of an industry standard.