bluuebunny/crossref_metadata_2025 huggingface dataset:
Laboratory Investigation of Polymer Producer TU-15A for MEOR Field Tests
Authors: Sugai Y. , Kishita A. , Hong C-X. , Enomoto H. , Chida T. , Zhou S-C.
Published: December 2007

Clostridium sp. TU-15A was isolated from the reservoir water from China jilin oil field. This microbe is a powerful polymer producer and expected for the effect on oil recovery.

This is the fundamental study on this microbe for the field trial and consists of following two experiments.

At first, cultivation experiments were carried out with TU-15A. This microbe reaches maximum phase at a day and increasing viscosity of the culture starts on second day. This result shows that the culture needs to be injected into reservoir within two days after inoculation. The relation between molasses concentration and the viscosity of this culture, which is pseudoplastic fluid is linear: about 40cP (at 10r.p.m) at molasses 4% and about 25cP at molasses 2%. From this result, it is possible to control the viscosity in reservoir. And adaptability to the environment in oil reservoir was investigated with following two incubation systems: micro-pore system and competition with indigenous microorganisms. TU-15A grew and produced polymer even under these conditions and there is not serious problem for cultivation in reservoir. In the examination with micro-pore system, this microbe grew slowly and reached maximum phase at forth day. This is an effective result for spread of culture in reservoir. In competition test with indigenous microorganisms, which were sampled from one block in Jilin oil field, the viscosity of this culture became low. Therefore it is necessary for TU-15A to test competition with indigenous microorganisms in selected target blocks again.

Secondly, flooding experiments were carried out with viscous culture of TU-15A with following two systems which were modeled with two sandpacks. One was five spot flooding pattern and the other was anisotropy of permeability. At the former experiment, two sandpacks total oil recovery was 73% after water flood and 12% of initial oil saturation after the culture injection. In the case of latter, two sandpacks total oil recovery was 68% after water flood and 15% of initial oil saturation after the culture injection. In both cases, high oil recovery were obtained from flow smaller sandpack and the change of flow caused these results by the culture injection. At the five spot flooding pattern, flow of injected fluid to flow smaller one improved from 22% at water flood to 47%: maximum of 56% and minimum of 38% and at the anisotropy of permeability, flow improved from 7% at water flood to 21%: maximum of 34% and minimum of 16% by injection culture. Moreover, the viscosity of culture was changed with two kinds of microbes in these experiments.

Jilin oilfield has an anisotropy of permeability and great effect is expected on oil recovery in this field with TU-15A from these results.
Insert Chamber Lift Experiences in Mara-La Paz Field, Venezuela
Authors: Gasbarri S. , Marcano L. , Inciarte J. E. , Faustinelli J. G.
Published: December 2007

Several types of fluids and well depths can be found within Mara-La Paz field. Different artificial lift methods have been used depending on the well characteristics. Gas lift is one of the most widespread methods used in the area, and gas compression facilities are used for artificial lifting many wells. The injection pressure is around 900 psi. Continuous gas lift injection is not always profitable, particularly for very low reservoir pressure. In this case, and depending on the well depth, intermittent gas injection may be used to decreased gas consumption and optimize the field.

Most of the wells on this field are too deep for a conventional intermittent gas lift installation. Chamber and plunger lift are alternative applications to improve the profitability of the wells. The purpose of the chamber is to accumulate more liquid volume per bottom hole flowing pressure increase and then, to produce more fluids per cycle compared to a conventional intermittent gas lift system.

Although chamber lift technology has been used for more than 4 decades, little information can be found in the literature about the intrinsic problems and statistics of success of this type of artificial lift system. This paper describes the performance of the chamber lift installations in Mara-La Paz field and the methodology used for design, diagnostic, and optimization of the systems.
A Unique Solution to Zonal Isolation Utilizing Foam-Cement and Coiled-Tubing Technologies
Authors: O'Rourke T. J. , Crombie D. L.
Published: December 2007

To effectively exploit a by-passed underpressured Devonian (D3) pinnacle reef, a horizontal re-entry was planned. Due to the presence of a gas cap and a nearby solvent bank in the reef it was essential that hydraulic isolation be achieved when cementing the build section liner in order to prevent gas migration during oil production from the new wellbore.

Coiled tubing was utilized to clean the formation face prior to cementing; foam-cement was then used to isolate the near wellbore and coiled tubing was once again used to clean out any excess cement from blocking the borehole prior to drilling ahead and cementing the liner.
Application of Geostatistics and Conventional Methods to Derive Hydraulic Flow Units for Improved Reservoir Description: A Case Study of Endicott Field, Alaska
Authors: Ratchkovski Artem , Ogbe David O. , Lawal Akanni S.
Published: December 2007

In this paper, we combine the geostatistical methods of conditional simulation with conventional methods of deriving flow units to characterize a section of the Endicott Field, North Slope of Alaska. Hydraulic flow units are generated using well logs, core data and core descriptions from 10 wells. Geostatistical techniques of sequential Gaussian simulation and sequential indicator simulation were used to obtain equiprobable realizations of the reservoir properties such as porosity and permeability.

Conventional interpolation techniques of inverse distance by power and kriging were also applied to describe the distribution of porosity and permeability in the developed flow units model. To validate conventional and geostatistical approaches, the fluid flow simulations of waterflooding were performed in the small section of Endicott Field. Results of the waterflood performance showed that geostatistical models give more detailed description of the reservoir heterogeneities compared to conventional methods.
Multiphase-Flow Properties of Fractured Porous Media
Authors: Rangel-German E. , Akin S. , Castanier L.
Published: December 2007

The fluid transfer parameters between matrix and fracture are not well known. Consequently, simulation of fractured reservoirs uses, in general, very crude and unproved hypothesis such as zero capillary pressure in the fracture and/or relative permeability functions that are linear with saturation. In order to improve the understanding of flow in fractured media, an experimental study was conducted and numerical simulation used to interpret experimental results.

A laboratory flow apparatus was built to obtain data on water-air imbibition and oil-water drainage displacements in fractured sandstone systems. During the experiments, porosity and saturation were measured along the core utilizing a Computerized Tomography (CT) scanner. Saturation images were reconstructed in 3-D to observe how matrix-fracture interaction occurred. Differences in fluid saturations and relative permeabilities caused by changes of fracture width have also been analyzed.

In the case of water-air imbibition, fracture systems with narrower fracture apertures showed more stable fronts and slower water breakthrough than the wide fracture systems. However, the final water saturation was higher in wide fracture systems, thus showing that capillary pressure in the narrow fracture has more effect on fluid distribution in the matrix. During oil-water drainage, oil saturations were higher in the blocks near the thin fracture, again showing the effect of fracture capillary pressure. Oil fingering was observed in the wide fracture.

Fine-grid simulations of the experiments using a commercial reservoir simulator were performed. Relative permeability and capillary pressure curves were obtained by history matching the experiments. The results showed that the assumption of fracture relative permeability equal to phase saturation is incorrect. We found that both capillary and viscous forces affect the process. The matrix capillary pressure obtained by matching an experiment showed lower values than reported in the literature.
Optimization of Slimhole Dual-Body Bits by Experiments and Computational Fluid Dynamics
Authors: de Sousa J. T. V. , Prohaska M. , Bencic A. , Millheim K. K.
Published: December 2007

This paper presents a detailed study on the optimization of slim-hole dual-body bits made in-house for use in Coring-While-Drilling (CWD). Investigations consisted of extensive coring and drilling laboratory tests in soft, medium and hard rocks. In addition, an apparatus was designed and built to investigate the effect of the rotary speeds on the pressure distribution underneath the bits. To calibrate the experimental work, Computational Fluid Dynamics (CFD) techniques were used to investigate the flow characteristics of the bits.
Badami Development
Authors: Repp S. A. , Ennis J. O.
Published: December 2007

Badami is the first "greenfield" production facility on the North Slope of Alaska in over 10 years. Smaller than previous developments and remote from existing infrastructure, Badami was sanctioned in February 1997 and began oil production on August 23, 1998. Innovative approaches to project definition and execution were applied in order to achieve project sanction and breakthrough performance as measured by cost and schedule. Lessons from Badami provide a model for the next generation of smaller remote developments in Alaska.

Badami was developed on a fast track with parallel activities in reservoir definition, facilities engineering, and permitting.

A facilities project alliance made up of BP and the primary engineering and construction contractors was formed at the start of the conceptual design phase. The intent of the alliance was to align the interest of BP and the contractors in a risk/reward profit scheme and to reduce development costs through the innovation and challenge to conventional approaches that motivated partners would provide.
Waterflood Pattern Allocations: Quantifying the Injector to Producer Relationship with Streamline Simulation
Authors: Grinestaff G. H.
Published: December 2007

SPE Distinguished lecturer Anil Kumar states that industry wide injection wells are overlooked, neglected, and mismanaged. Historically, injection patterns have been described by neighboring producers. Production is allocated back to injectors using angle open to flow or volume and distance weighting methodology. These static allocation methods poorly represent the physics involved in determining flow paths in the reservoir between wells.

Through the use of streamline simulation, Dynamic Injection Pattern Allocations accurately describe waterflood patterns through time. By quantifying the injector to producer relationship, inefficiencies in the waterflood are readily seen and the benefits of injection well work quantified. Waterflood injector rates can be set to maximize oil production, instead of maximizing water injection.

This paper demonstrates how to use streamline simulation to proactively manage a waterflood. The paper focuses on three areas: 1) how streamline models require a different approach to simulation, 2) using streamlines to find inefficiencies in the waterflood and set injection targets, and 3) the benefits of a history matched model.
Schrader Bluff CO2 EOR Evaluation
Authors: McKean T. A. M. , Thomas A. H. , Chesher J. R. , Weggeland M. C.
Published: December 2007

A CO2 miscible gas enhanced oil recovery (EOR) water-alternating-gas (WAG) development scheme is being evaluated as a method to enhance viscous oil recovery from the Schrader Bluff reservoir at Milne Point.

A CO2 EOR development offers the opportunity to reduce greenhouse gas emissions, while at the same time enhancing oil recovery. Under such a scheme, CO2 would be extracted from the exhaust of gas-fired turbines and compressed for injection along with NGL in a WAG flood. There are no known analogues using this approach to increase recovery in a viscous oil reservoir.

Fully compositional simulation models were constructed to investigate the behavior of the injected CO2/NGL mixture as compared with conventional waterflood recovery schemes. An assessment of simulator capability was made, and uncertainties in reservoir properties and development options were examined with a variety of models. The overall performance of the CO2/NGL solvent was predicted for pattern elements, scaled up to development pad size, then to a multi-pad large-scale development.

The evaluation concludes that CO2 EOR WAG has the potential to significantly increase recovery compared to water-flooding, and that a large volume of CO2 could be permanently sequestered in the reservoir. The economic viability of the project depends on the value attributed to the sequestered CO2 in the form of emission permits which are sold or traded.
Reservoir Engineering Aspects of Horizontal Wells in Stochastic Naturally Fractured Gas Reservoirs
Authors: Hatzignatiou D. G.
Published: December 2007

This work presents the application of a newly developed gas reservoir numerical model for simulating gas flow in naturally fractured reservoirs capable of handling stochastically generated natural fracture network systems. The motivation for this study is based on the inability of traditional dual-porosity reservoir models to represent effectively fracture networks, in the form of either clusters of intersecting fractures or fracture discontinuums. The simulator assumes single-phase, dry-gas flow in a bounded, naturally fractured gas reservoir. The model decouples fluid flow in fracture and matrix domains, thus solving a one-dimensional matrix flow problem to compute the volumetric flow rates from matrix into fractures and/or wellbore(s). Subsequently, the model uses the recharge fluid rates entering the fractures at the middle point of each fracture segment to compute the pressure and flow rate distributions at each node of the system by solving a two-dimensional fluid flow problem in the fracture domain. The system of natural fractures is produced using a stochastic fracture-porosity model which generates fracture network realizations and provides data regarding the natural fractures (location, apertures, density, clustering, etc.). The gas reservoir simulator is validated, for simplified reservoir problems, against a commercially available three-dimensional, three-phase, black-oil simulator and used to conduct a preliminary study of the pressure behavior and recovery of natural gas from a tight gas formation in Paludal Sands of the Rulison Field, Piceance Creek Basin in Colorado. Simulation results of a horizontal well in this naturally fractured gas reservoir indicate that well location within the flow region, degree of clustering, fracture density, fracture aperture distribution, and degree of fracture interconnectedness are very significant factors influencing gas production rates, gas recovery and reservoir drainage effectiveness.
Multiple Hydraulic Fractures in Horizontal Wells
Authors: Wan J. , Aziz K.
Published: December 2007

A well model is required to relate the well rate to the well pressure and the block pressure containing the well for the modeling wells in simulators. The well index is calculated automatically by simulators for conventional wells, but it is generally calculated by the user and supplied in the input while modeling non-conventional wells, when the default procedure available in commercial simulators is not adequate.

In this paper we describe a new analytical solution for horizontal wells with multiple fractures. The fractures can be rotated at any horizontal angle to the well and they need not fully penetrate the formation in the vertical direction. This three-dimension solution for hydraulically fractured wells is obtained by applying Fourier analysis to a two-dimensional solution, therefore this three-dimension solution is easy to obtain when the two-dimensional solution is available. The analytical solution provides the well pressure that can be combined with a numerically computed gridblock pressure to obtain the well index (WI). Results of our rigorous solution are compared with empirical approaches currently in use for calculating the well index and the productivity index. Examples are given when horizontal wells with fractures are modeled using our new approach and conventional methods. These results demonstrate the need for computing the correct WI.
Management of Well Production Using Real-Time Expert Systems Technology
Authors: McLean Dan , Wilcoxson Jim , Clay Roger
Published: December 2007

Management of well production for artificially lifted wells can be improved using expert system technology to combine real time sensor information with production engineering knowledge rules. When abnormal conditions exist on a gas well it is not always apparent that there is a problem until significant production loss and/or the results of other regulatory control system alarms become apparent. By applying expert system technology and elements of artificial intelligence, visualization of well performance in relation to the well design can be presented to operations personnel in real time. The well performance can then be maximized once the operating constraints are known and algorithms to optimize production can logically follow. The expert application describes in this paper demonstrates this ability and can be extended easily to multiple well sites or multiple platforms and fields.
Planning Exploratory Drilling for Coalbed Methane Resource Development in Rural Alaska
Authors: Ogbe David O. , Clough James , Bott Jamie , Hawley Mary A.
Published: December 2007

The state of Alaska contains over 40 trillion cubic feet of conventional natural gas and 5 trillion short tons of coal reserves. Although the actual extent and magnitude of producible gas from Alaska's remote coal basins are unknown, the Alaska Department of Natural Resources postulates that if only 10% of the estimated 1,000-trillion cubic feet of methane gas is recoverable, this coalbed methane resource would triple the State's current proven conventional gas reserves

Exploratory drilling is the key to assessing the potential of the coalbed gas resources from Alaska's vast coal reserves. In this paper, we evaluate the feasibility of drilling exploratory wells for developing coalbed methane resource as alternative energy in rural Alaska. The paper presents detailed analysis of the costs of drilling exploratory wells, including logistics and transportation, geological and hydrologic testing at three sites in rural Alaska.

The results of the study show that the cost of drilling and testing two exploratory test wells is about $1.8 million at each site. The study recommends guidelines for site selection, well planning, and design of drilling programs to support coalbed methane development in rural Alaska.
A Fundamentally New Model of Acid Wormholing in Carbonates
Authors: Gdanski Rick
Published: December 2007

A new theoretical model has been developed to describe the chemical reactions of acid in porous carbonate media. For the past 20 years, the three major unanswered questions regarding wormholing when acid is pumped into carbonate formations have been the following: (1) How many dominant wormholes are created? (2) What is the spatial distribution of those dominant wormholes along the wellbore? (3) What is the leakoff profile from the dominant wormholes under radial flow conditions? This paper presents a model that proposes answers to these three basic questions. Once these questions are answered, the reaction of acid in the matrix and the interaction of wormhole development become straightforward. The new model requires a major paradigm shift in the understanding of matrix carbonate acidizing and the variables that control wormhole growth. Parametric studies that were conducted with the new theory are presented. It was found that wormhole length is predominantly controlled by matrix porosity and volume of acid pumped—not by reactivity. It was found that wormhole diameter is predominantly controlled by reactivity and contact time. The new theory confirms classically held guidelines for matrix acidizing of carbonates, and gives insight on how to improve matrix carbonate acidizing treatments. The new model also accommodates the effects of permeability anisotropy caused by natural fracturing or layering effects
Chelating Agents in Sour Well Acidizing: Methodology or Mythology
Authors: Brezinski Michael M.
Published: December 2007

Metal chelating materials have been used as iron control agents in acidizing treatments for many years. There are several disadvantages associated with use of the various commercially available products. These disadvantages include low solubility and high toxicity. Furthermore, recent evidence casts considerable doubt on the effectiveness of common chelating agents for iron control in sour environments.

A relatively simple procedure will be presented that allows preparation of pure metal (calcium and iron) chelant complexes. These complexes serve as models for the in-depth evaluation of various chelating agents over a broad range of temperatures and fluid compositions and have been characterized with respect to solubility and thermal stability in spent acid fluids. The experimental results show loss of solubility of calcium complexes as well as thermal decomposition of ferrous complexes at relatively low temperatures. Implications of these results will be discussed.

The problems are exacerbated in sour environments where iron sulfide precipitation occurs at a very low pH. New evidence will be presented that shows iron sulfide precipitation will occur below the pH range where chelating agents are effective. The precipitation of iron sulfide has been found to be dependant upon formation basicity and NOT the overall acidity of the bulk fluid as commonly believed. The result implies that simple equilibrium calculations may not reliably predict the chemistry that will occur downholeand must be used with caution.

The conclusion drawn from these results is that the only effective method of preventing precipitation of iron sulfide during sour well acid treatments is to remove H2S from the fluid with sulfide scavenger products. The elimination of large quantities (6–36 kg/m3, or 50–300lbs./Mgal) of chelating agents will have significant cost savings with regards to fluid cost. The evidence provided in this paper shows that these products are not effective and even worse, may precipitate in the formation and cause severe damage
New Fluosilicic Acid System Removes Deep Clay Damage
Authors: Da Motta Eduardo P. , C. M. Dos Santos J. Altamiro
Published: December 2007

Recent models for sandstone acidizing have shown that the secondary reaction of fluosilicic acid (H2SiF6) with clays plays a significant role in the removal of formation damage. The conventional wisdom is that possible precipitation during the secondary reactions can adversely affect treatment success. However, this paper presents laboratory experiments with Berea cores and two Brazilian sandstone cores, as well as field tests, which show that fluosilicic acid can be injected, by itself, into a sandstone reservoir without causing any damage at all. Quite the contrary, mixtures of fluosilicic acid with a proper amount of hydrochloric acid (HCl) or an organic acid such as acetic acid (HAc) have been able to improve the performance of two Brazilian water injection wells by removing clay damage. These two wells, that were injecting 11 and 15 m3/d, are sustaining injection rates at or above the desired quota of 30 m3/d, five months after the treatments. The treatments were monitored with a real-time monitoring program, that showed that the skin factor has dropped from about 30/40 to zero. Besides having a lower cost than conventional HF mixtures, the main advantage of the new acid system is that it reacts mostly with clays and feldspars, but almost does not react with quartz. This way, it can dissolve damage without weakening the rock structure, what makes it suitable for deep damage removal. The low cost of H2SiF6, which is a byproduct of sodium fluoride manufacturing, makes it also a viable option for routine acidizing operations, that would normally require the use of an HF acid system.
Screen Sizing Rules and Running Guidelines to Maximise Horizontal Well Productivity
Authors: Malbrel Christophe , Procyk Alex , Cameron John
Published: December 2007

Flow density across sand control screens in horizontal wells is very low. This is very favorable to the selection of screen-only completions as a cost effective sand control measure. However, phenomena specific to horizontal well completions have prevented them being as successful as they could be: 1) deployment contaminates the screen and reduces well productivity; 2) formation sands can mix in the annulus around the screen, modify the apparent sand sieve analyses, and affect the screen's ability to retain sand.

Therefore, screen sizing must not only include the selection of a screen medium capable to retain formation sands and tolerant to impairment caused by completion fluids, it also requires a careful review of other screen design features such as diameter, OD/ID ratio and the screen/blank ratio. To help select screens, sizing guidelines have been developed based on formation sand characteristics such as average size (D50) and uniformity (D40/D90).

A well productivity model has also been developed to assist in screen selection. Using reservoir characteristics such as permeability, heterogeneity, consolidation, design flowrate and fluid characteristics, it shows that incomplete screen clean-up can seriously affect well performance. While gravel packing reduces productivity losses associated with poor screen clean-up, minimizing screen impairment during deployment and/or cleaning it afterwards can prove to be a less costly alternative. A "Mud Plugging Index" is proposed to monitor screen plugging by a given drill-in fluid and help optimize fluid conditioning on the rig. Using centralizers on the screen during deployment and back-flowing fluid with a washcups assembly will also help enhancing well productivity.
An Improved Model for Predicting High-Rate Cased-Hole Gravel-Pack Well Performance
Authors: Unneland Trond
Published: December 2007

In this paper, an improved analytical model for predicting high-rate gravel-packed well performance is presented. The recommended model is based on serial flow through the perforation tunnels filled with formation sand and gravel, and has been calibrated with field data from three major oil fields in the Norwegian sector of the North Sea. The effective tunnel permeability is found to be a function of original formation permeability and gravel size. A new correlation for the high-velocity coefficient as a function of effective tunnel permeability is also given. The model, combined with the new correlations, gives a satisfactory match between measured and calculated pressure drop. A guideline for predicting pressure drop in high-rate cased-hole gravel-packed wells is presented, aiming at improving the tools for performance prediction for future wells. With these tools, specific targets can be identified for improvements in wells, thereby ultimately increasing well production and field profitability.
Observed Variations in Hydrocarbon Reservoir Bacterial Populations with Temperature: A First Step in Modeling the Bacterial Populations of Hydrocarbon Reservoirs.
Authors: Wood Jonathan M. , Spark Iain S. C.
Published: December 2007

Anaerobic bacteria have been isolated from hydrocarbon reservoirs, varying in depth of burial from 3500ft to 15000ft, at temperatures up to 150°C. These bacteria can be introduced in to the reservoir as a result of drilling operations and/or injection water; however in many cases the bacteria are indigenous to the oilfield reservoir. These bacterial populations have been shown to vary with changes in temperature, affecting their type and bacterial by-products such as pyrite, biopolymer and hydrogen sulphide gas. Using this thermal information, it is possible to construct a model from the incubation of preserved oilfield core samples in various growth media at selected temperatures to determine those areas at high risk of microbial formation damage. This is only a simple first step model as there are many other factors, some only poorly understood, that can affect the growth rate of bacterial populations in a hydrocarbon reservoir such as nutrient availability, sulphide, nitrate, sulphur, hydrogen and phosphate content for example.
External Filter Cake Properties During Injection of Produced Waters
Authors: Ochi J. , Detienne J-L , Rivet P. , Lacourie Y.
Published: December 2007

The re-injection of produced waters for pressure maintenance becomes more and more attractive in the industry since the environmental regulations for rejection (sea, rivers, deep aquifers) are more constraining associated with increasing surface treatment costs. One important difficulty in this re-injection process is the ability to predict the impact of water qualities on well injectivities. This is mainly due to the poor knowledge in the mechanisms of porous media damage by mixtures of micronic solid particles and oil droplets which are the main components of produced waters. In a first attempt this paper does not deal with the matrix internal filter cake formation. It focuses on the external filter cake build-up and flow properties which are believed to have the larger impact on well injectivity over most of the well life. It is shown that the injection of micronic dispersed oil leads to compressible filter cakes with very low permeabilities in the micro-darcies range. The retention on the filter is amplified by oil agglomeration while oil passing through the filter is dispersed in particles smaller than the filter pore throats. They become finer and finer as the pressure increases and are able to migrate deeply within the reservoir without adverse internal injectivity effects. These results on synthetic oil emulsions are compared to a real produced water behavior.
The Redevelopment of a Mature Waterflood Through the Application of Horizontal Multilateral Drilling Technology in Preparation for Tertiary CO2 WAG Operations
Authors: Dollens Kimberly B. , Larson Dana C. , Anthony Terry L. , Howell David A , Jones Tim A.
Published: December 2007

Multi-lateral horizontal drilling technology has been employed since late 1996 in the mature carbonate waterflood of the Ratherford Unit, Greater Aneth Field, San Juan County, Utah, in preparation for the implementation of a CO2 Water-Alternating-Gas (WAG) tertiary recovery project, planned for initiation in 2000. The program of multi-lateral reentries of 21 existing producers and 24 existing injectors over a two-year period (late-1996 through late-1998) was comprised of 100 laterals targeting the highly-stratified layers of the Upper Desert Creek.

Miscible flooding of the low-permeability Pennsylvanian Upper Desert Creek Zone I has been shown by analysis of the adjacent McElmo Creek Unit to be economic only through increased vertical/areal sweep efficiencies and processing rate enhancements obtained by the application of horizontal injector-producer pairs. The results of this study were confirmed by the 1994 - 1995 Ratherford Unit horizontal injection well drilling program, the 1996 Ratherford Unit multi-lateral production well drilling program, and the 1995 horizontal CO2 pilot pattern in the adjacent McElmo Creek Unit.

This paper will review the basic geologic and engineering concepts behind the application of horizontal drilling technology within the Ratherford Unit, detail the multi-lateral techniques employed and process improvements made through time, and summarize the actual field results.
Integrating Core Porosity and Sw Measurements with Log Values
Authors: Weiss W. W. , Wo S. , Balch R. S. , Roe J. , Fagrelius K. , Kendall R.
Published: December 2007

Well logs and cores are used to define formation thickness, porosity, and water saturation. These data are required to design well completions and to prepare workover and reservoir management plans. The presence of shale (clay) in the pay zone complicates log interpretation. This paper presents a methodology utilizing a neural network to reconcile the differences between density log effective porosity and plug core total porosity values in a shaly, laminated Cretaceous sandstone.

Core plug measurements are typically taken in the better pay intervals and generally do not include the shale laminations evident in core photographs. Log measurements do include the heterogeneity that is evident in core photographs, but the log measurements represent an average of a 6-to-36-in. section that does not reflect the small scale variability. A multivariable correlating technique was used to associate gamma ray, density, and shallow and deep resistivity logs with core plug porosity measurements.

Core water saturation values were used to tune a shaly sand water saturation model. The sw model was used to choose between plug core porosity, density log porosity, or neural network porosity as the preferred measurement to use with induction log resistivity to estimate water saturation. The porosity and water saturation values were then used to construct bulk volume oil and bulk volume water logs that were combined to identify productive zones.

A case history format is used to explain the approach developed to correlate the four dependent variables measured by the logs with the core porosity and water saturation measurements. The subject field is an 80-well Gallup pool located on the southwest flank of the San Juan Basin of northwest New Mexico.

The high clay content of the Muddy Formation in the Powder River Basin is known for contributing to errors in water saturation estimates. If modern logs capable of resolving thin beds are not available, this methodology can be applied to the Muddy, the Gallup and other Cretaceous reservoirs in the Rockies that contain thin shale laminations.
Gas Condensate Well Test Analysis Using a Single-Phase Analogy
Authors: Xu Shaosong , Lee W. John
Published: December 2007

This paper shows that a simple, single-phase analogy using a standard dry gas pseudopressure transformation in interpreting transient buildup pressure data from a gas condensate well gives a good estimation of permeability. Under certain conditions, this method gives good estimates of damage skin, too. These results are not affected by average reservoir pressure.

We used a commercial fluid PVT package and an EOS-based compositional simulator to characterize the phase behavior of retrograde gases during reservoir depletion, to compare gas and condensate PVT properties in situ and at lab conditions, and to model a vertical well under varying conditions. Then we analyzed the simulated buildup transient pressure by using a single-phase analogy incorporating a radially composite model and compared the results with reservoir simulator inputs and outputs.

The numerical experiments using three actual fluid samples show that, during reservoir depletion, the vapor properties in situ are a function of pressure only, and correlate very well with z factor, gas molar density and viscosity obtained in lab constant composition expansion (CCE). The condensate PVT properties in situ depend on pressure, production mode and reservoir properties. But the effects of variables other than pressure are usually small and are constrained within a certain pressure range. As a rule, the leaner the retrograde gas, the smaller the deviations. As a practical matter, the correlations between condensate oil PVT properties obtained from lab CCE and the values in situ are also quite acceptable.

Our reservoir simulation showed that the pressure buildup responses can be classified into two types. In the first type, the shape of the pressure derivative suggests a well in a radially composite two-zone reservoir. In the second type, the pressure derivative suggests a well in a radial three-zone reservoir.

Our interpretation of 30 simulated cases using a radially composite two-zone model shows that a single-phase analogy gives a good estimation of permeability but underestimates condensate bank size. We cannot estimate damage skin from the first type of pressure response, but the estimation from the second type is acceptable.
Pore-Scale Modeling of Multiphase Flow in Fractures and Matrix/Fracture Transfer
Authors: Hughes Richard G. , Blunt Martin J.
Published: December 2007

We use pore-scale network modeling to simulate imbibition in fractures and the matrix/fracture interaction. We represent the fracture as a two-dimensional lattice of conceptual pores and throats. We allow flow in connected wetting layers that occupy roughness and crevices in the pore space. We model piston-like advance with a capillary pressure that accounts for the curvature of the meniscus due to the fracture aperture, as well as the curvature of the wetting front in the fracture plane. We show that the model gives results that are insensitive to the resolution or pore spacing of the network. To account for viscous forces, the wetting phase pressure is computed assuming a fixed conductance in wetting layers. This pressure, in combination with the local capillary pressure, is used to determine the displacement sequence. A matrix is incorporated by surrounding the two-dimensional fracture plane by a three-dimensional network of pores and throats.

We model multiphase flow in a real fracture using an aperture distribution obtained from CT scanning. The simulated saturation distributions agree with those measured using in situ imaging. We also study the matrix/fracture transfer in a large three-dimensional network.
Up-scaling of Multiphase Flow Functions Using a Steady State Flow Model
Authors: Virnovsky G. A. , Friis H. A. , Lohne A. , Skauge A.
Published: December 2007

A concept of multiphase up-scaling based on steady-state flow approach was introduced in Ref. 2. It enables efficient calculation of effective properties through a numerical solution of steady-state 2-phase flow equation in 1D. The extension of this concept, i.e. steady-state multiphase flow, on 2 and 3 space dimensions, is studied below.

We present a model for efficient direct up-scaling in 2 and 3D. The developed numerical model simulates steady-state multiphase flow in heterogeneous reservoirs with account for viscous, capillary and gravity forces at a given external pressure drop. We utilize the developed model to directly compute effective properties in 2D, and present examples that show the dependence of effective relative permeabilities and capillary pressure on the magnitude of the external pressure drop, and also study the convergence of the effective relative permeabilities and capillary pressures towards the viscous limit functions.
Experiments and Modeling of High-Velocity Pressure Loss in Sandstone Fractures
Authors: Skjetne E. , Klov Statoil, T. , Gudmundsson J. S.
Published: December 2007

In this study we measured high-velocity pressure loss over Bentheimer sandstone fractures with varying fracture widths. Direct measurements of the roughness showed that the fractures were self-affine. The new results support the rough fracture high-velocity pressure loss model. The high-velocity pressure loss was described by a Forchheimer equation with a dominating square term. The square term is a power law in fracture width, and the power is given by a roughness exponent. For low velocities the pressure loss was not described by the Forchheimer equation. In agreement with theory, there exists a weak inertia flow regime, which separates the Darcy flow regime from the Forchheimer flow regime. An expression for the incremental high-velocity skin of a pinched-out hydraulic fracture was derived. The skin is a power law in fracture width.
Oil Recovery in a Fracture of Variable Aperture with Countercurrent Imbibition: Experimental Analysis
Authors: Lee Jaehyoung , Kang Joo M.
Published: December 2007

A parallel plate model is widely used to simulate flow in a fracture due to simplicity of idealizing the fracture. However, a real fracture has characteristics of variable aperture in nature. To assess the effect of variable aperture in water flooding, we performed water injection tests through fractured samples initially saturated with oil.

A casting method is employed to obtain aperture distribution of real fractures. From these results, we represented the morphology of the fractures using statistical parameters such as mean, coefficient of variation (Cv), skewness (S), and an anisotropy ratio. Water is injected into unfractured sandstone samples with constant rate and into artificially fractured sandstones with an increasing flow rate.

We interpreted cumulative oil recovery curves from the fractured rocks using corresponding statistical parameters in the results. The results show that morphology of a fracture has a significant effect on oil recovery as well as water injection rate. As Cv and S increase, overall efficiency of oil recovery decreases. Anisotropy ratio affects the breakthrough time of injected water and overall oil recovery as significant as Cv. At lower anisotropy ratio such as less than one, early breakthrough and poor oil recovery have occurred. The effect of the statistical parameters is pronounced as injection rate increases. We observed a point where imbibition rate shows identity regardless of fracture morphology, if both flow rate of injected water and matrix characteristics are the same.
Truncation De-noising in Transient Pressure Tests
Authors: González-Tamez Federico , Camacho-Velázquez Rodolfo , Escalante-Ramírez Boris
Published: December 2007

Truncation noise affects the interpretation of transient pressure tests when the total pressure change is very small compared to the total measurement scale of the tool. There are situations, mainly in high permeability reservoirs, where the maximum pressure variation is of the order of one thousandth of the total scale of the probe. Noise greater than one thousandth of the total pressure change hides pressure signals related to the characteristics of the reservoir; even when the accuracy of the tool could achieve one part by million of the total scale. This situation makes almost impossible the interpretation with the logarithmic derivative.

It is demonstrated in this paper that the frequency spectrum of noise is in the same frequency band that frequencies associated to the reservoir signal. By using a fitting procedure and wavelets, the signal-noise ratio (SNR) of pressure tests with truncation noise is improved in most of the cases up to 8 dB. This situation is equivalent to measure the maximum pressure change of the reservoir with a tool of one bit of additional effective resolution. Greater improvements can be obtained when only Gaussian white noise is present in the pressure signal. This result offers the possibility to reuse old noisy derivative data logs, especially pressure tests from high permeability reservoirs. This contribution will permit to utilize derivative interpretation techniques in a more appropriate way.

The efficiency of the proposed filtering technique is demonstrated with synthetic and field data pressure tests.
Application of Tracers to Monitor Fluid Flow in the Snorre Field: A Field Study
Authors: Dugstad Ø. , Aurdal T. , Galdiga C. , Hundere I. , Torgersen H. J.
Published: December 2007

This paper discusses the applications of gas and water tracers in the Central Fault Block (CFB) of the Snorre Field in the North Sea. An extensive tracer program was initiated in 1993 to improve the understanding of the flow dynamics in the field.

The CFB of Snorre has been produced by WAG injection since 1994. The tracer program has involved 3 injectors and 4 producers. Tracers applied were perfluorinated hydrocarbons (PFCs) and SF6 as gas tracers. As water tracers tritiated water (HTO), chemical SCN− and radioactive S14CN− have been applied in addition to the new tracer 4-fluoro benzoic acid (4-FBA).

Results from this integrated tracer study have improved the understanding of fluid flow and WAG injection efficiency in the reservoir. The tracer program will be continued and will also be expanded to other fault blocks.
Investigation and Modeling of Complex Water Influx Into the Sandstone Reservoir, Khafji Oil Field, Arabian Gulf
Authors: Nishikiori Nobuo , Hayashida Yasuyuki
Published: December 2007

This paper describes the multi-disciplinary approach to investigate and model complex water influx into the water driven sandstone reservoir, which takes into account vertical water flux from the lower reservoir as suspected supplemental source.

The Khafji oil field is located offshore in the Arabian Gulf and two underlying Middle Cretaceous sandstone reservoirs are investigated to understand the water movement during production. Both reservoirs are supported by a huge aquifer and had the same original oil-water contact. The reservoirs are separated by a thick and continuous shale so that the upper reservoir is categorized as edge water drive while the lower reservoir as bottom water drive. However, water production was observed at the central up-structured wells of the upper reservoir in the period much earlier than expected, which makes the modeling of water influx complicated as it is difficult to explain this phenomenon only by edge water influx.

In this study, engineered reservoir description was first performed to investigate water influx into the upper reservoir. Pressure and production history was comprehensively reviewed, which diagnosed that there existed anomalous higher pressure area in the upper reservoir. Moreover, anomalous temperature profiles were observed in some wells in the same area. At the same time, watered zones were trailed through TDT time-lapse analysis by which front of watered zone and its thickness were evaluated by both qualitative and quantitative manner. In addition, 3-D seismic survey has been conducted recently for the field and faults passing through the two reservoirs were recognized. Therefore, as results of data review and subsequent investigation, conductive faults as supplemental fluid conduits from the lower reservoir were suspected. Pulse test was then designed and suspected communication between two sandstone reservoirs and conductivity of a fault are currently under investigation.

Finally, an improved full-scale numerical reservoir model was constructed to model complex water movement, which includes suspected peculiar water from the lower reservoir. Employment of two kinds of water influx -one is conventional edge water and another is supplemental water invasion from the aquifer of the lower reservoir through conductive faults-achieved water breakthrough match. Furthermore, complex nature of water movement in the reservoir was accurately modeled by use of precise classification of rock type and adoption of pseudo relative permeability accounting for upward increasing or decreasing trend of permeability.
Tidal-Force-Influenced Pressure Transients for Estimating Compressibility in a Fractured Reservoir
Authors: Chang Eric , Firoozabadi Abbas
Published: December 2007

Total compressibility in a fractured reservoir is estimated using the pressure response due to gravitational potential variations. Both the moon and the sun gravitational potentials are accounted for using the full expression by inclusion of longer-period components. The semi-diurnal and diurnal pressure data show substantial long-term variations. The gravitational potential also contains the same variation trend; the ratio between the potential and pressure has a fairly uniform value over successive cycles. The computed total compressibility is also fairly constant and independent of the cycle. Results show the effects of the time interval over which the pressure measurements are performed as well as the location.