bluuebunny/crossref_metadata_2025 huggingface dataset:
Field Evaluation of Different Recovery Processes in Zone 4 of the Prudhoe Bay Field
Authors: McGuire P. L. , Foakes A. , Spence A. P.
Published: December 2007

This paper summarizes the core analysis data and the reservoir simulation history match of two Zone 4 cores in areas of Prudhoe Bay that were produced by different recovery mechanisms. It also describes the process comparison studies and the updip waterflood and miscible gas flood field-tests which resulted from those studies. One Zone 4 core was taken in the gravity drainage area and one Zone 4 core was taken in the waterflood/WAG area. Both cores were history matched with a reservoir simulator to reproduce the measured oil saturations and to determine the ultimate recovery potential of the process currently being employed. The success of the simulations in matching the actual core data increased our confidence in the accuracy of the ultimate recovery forecasts. Additional simulations were run to evaluate converting part of the updip portion of Zone 4 from gravity drainage to some form of water and/or miscible gas injection. These simulations indicated that the gravity drainage process was leaving high oil saturations behind the gas front that could not be produced economically because of excessive gas-oil ratios (GORs). Both water injection and miscible gas injection mobilized large volumes of oil and dramatically reduced GOR. This behavior has been observed in early field-test results.
Propagation of Chromium (III) Acetate Solutions Through Dolomite Rock
Authors: Jin H. , McCool C. S. , Willhite G. P. , Green D. W. , Michnick M. J.
Published: December 2007

Chromium(III)–polymer gel systems are often used in permeability modification treatments for flow control. Treatment of the carbonate rock matrix by these systems is of concern because rock-fluid interactions can lead to loss of chromium and thereby limit significantly the depth of penetration of a gel treatment. This paper describes a study of chromium retention in dolomite cores and demonstrates that precipitation of chromium is the principal retention mechanism. Displacement experiments were conducted in which chromium acetate solutions were continuously displaced at different flow rates through Baker dolomite cores. In some experiments, the cores were shut in and the resident fluid displaced and analysed to determine chromium retention during the shut-in period.

There was significant retention of chromium in the core in both continuous and shut-in experiments. In the continuous displacements, effluent concentration profiles were a function of flow rate, indicating that the retention was a rate-dependent process. The presence of KCl increased the retention rate. At the lowest flow rate used, effluent chromium concentration approached a steady-state value that was much smaller than the injected concentration. The retention capacity of the rock appeared to be infinite.

Chromium concentrations at various residence times were compared to values predicted from a kinetic model developed for precipitation from bulk solutions. The kinetic model fit the precipitation rate data well and is consistent with the conclusion that precipitation is the principal retention mechanism. However, the induction period observed in bulk solutions was not present in the data taken in the cores. Precipitation occurred faster in the cores than in the batch experiments. The experimental results indicate that chromium is precipitated at a relatively high rate when chromium acetate solution is in contact with dolomite core material. This loss of chromium will inhibit gelation and limit the depth of penetration of a gel system in dolomite matrix rock.
IOR: The Brazilian Perspective
Authors: Shecaira Farid S. , Branco Celso C. M. , de Souza Antonio L. S. , Pinto Antonio Carlos C. , de Holleben Carlos R. C. , Johann Paulo R. S.
Published: December 2007

The intent of this paper is to summarize the IOR evolution in Brazil and its perspectives for the future. First of all, a brief history of the oil industry in Brazil is presented, with special prominence to the establishment of the oil industry monopoly in 1953. Next, the main IOR efforts carried out by the industry are reported, beginning in the sixties with water injection in onshore fields, and subsequently with the use of several tertiary recovery methods. The gradual increase in oil production in offshore areas, as from the late seventies, changed the IOR panorama. Presently, water injection is the main IOR activity in offshore fields, which account for approximately 74% of the Brazilian daily oil output. The discovery of oil in deeper waters, as well as more recent facts, such as the enactment of the law breaking, in 1997, the mentioned Brazilian oil industry monopoly, added new components to the industry organization. These new facts can be of major importance in the future development of IOR activities in Brazil
Experimental and Field Results on the Use of Heavy Crude Injection to Control Gas Production in Light/Medium Crude Wells
Authors: Andarcia L. , Perez-Perez A. , Alvarez J. M.
Published: December 2007

Many heavy crudes show foaminess at surface conditions. The foam formed is usually very stable and can remain in an open vessel for several hours. This stability is especially obvious when taking fluid samples from producing wells. The emphasis of recent research on "foamy" crudes has been on explaining the unexpectedly large recovery efficiencies of these crudes by solution gas drive (so-called cold production). This work studies a different aspect of these crudes, namely their ability to reduce gas production in light/medium oil wells. As far as we know, this is the first application of foamy crudes to reduce produced gas-oil ratio (GOR). If successful, the technology should be less expensive than polymer gel or foam treatments (the competing technologies for lowering GOR) because no formulation is needed and there are no expensive chemicals involved.

The ability of foamy crudes to reduce gas production GOR is supported by experimental results. We conducted four experiments in sand packs under pressures and temperatures typical of Venezuelan light/medium crude oil reservoirs. The experiments were primary depletions done until a relatively large gas-oil ratio (GOR = 4000 scf/stb) was reached. At this point, we injected a slug of foamy crude through the producing side of the pack and continued the depletion. Slug sizes of the foamy crude ranged from 0.05 to 0.1 of pore volume. We monitored the experiments through the produced GOR, gas and oil rates and pressure profiles.

The experiments showed dramatic declines of GOR, ranging from the starting value of 4000 scf/stb to almost to the solution gas-oil ratio measured at the existing pressure. This represents a GOR reduction of up to 96%. The average of all tests had an incremental oil recovery of 8% after the injection of the foamy crude. As a result of the lab experiments, we began a pilot test in a mature medium oil field (Acema 200, San Tomé, Eastern Venezuela). The slug size was 150 bbl of foamy crude, which penetrated an average of 12 ft into the reservoir. After one month of monitoring, this field test showed an incremental oil recovery of up to 2000 bbl and a GOR reduction of 80%. The oil production rate increased by 328%, therefore the application cost of 5500 $ US was recovered by the second day of production. We measured a sudden increase of the GOR 3-1/2 months after the heavy oil injection.
Optimal Injection Strategies for Foam IOR
Authors: Shan D. , Rossen W. R.
Published: December 2007

Miscible-gas foam field trials have employed a variety of injection strategies, with mixed results. Using simulation, we compare foam-injection strategies in homogeneous reservoirs with a variety of foam models.

The optimal injection strategy for overcoming gravity override with foam in a homogeneous reservoir is alternating injection of separate, large slugs of gas and liquid at fixed, maximum-allowable injection pressure. This strategy minimizes both gravity override and time of injection, with minimal rise in injection-well pressure. Injection of gas at maximum pressure can partially reverse the effects of gravity slumping of surfactant during injection of liquid. The process is remarkably insensitive to the detailed properties of the foam, as long as foam does not collapse abruptly and completely at a "limiting water saturation" Sw*.

An idealized model for the process reveals the mechanisms responsible for process success, why injection at fixed injection pressure is better than injection at fixed rate, and why details of foam behavior play a secondary role in sweep efficiency.

Extreme care is needed to exclude the effects of numerical artifacts in simulating such a process, especially if foam collapses abruptly and completely at Sw*. In that case numerical dispersion may produce plausible, but inaccurate, simulation results.
Estimation of Foam Mobility in Heterogeneous Porous Media
Authors: Kovscek A. R. , Bertin H. J.
Published: December 2007

It has been shown experimentally, both here and elsewhere, that foaming gas is a promising technique for achieving mobility control and diverting injected fluid to low permeability strata within heterogeneous porous media. However, the factors most important for diversion have not been stated and explored definitively. Gas mobility in the presence of foam depends critically on foam bubble size; bubble size may vary with permeability, porosity, surfactant type and concentration, and the velocity of liquid and gas. This paper adopts a local-equilibrium, scaling perspective to describe quantitatively foamed gas mobility within heterogeneous porous media. Conventional and percolation network scaling ideas are employed. The equations developed indicate, for instance, that porosity plays an important role in setting gas mobility because it reflects the relative abundance of foam germination and termination sites per unit volume of porous media. Liquid velocity is also important because gas mobility is inversely proportional to this factor. Predictions are checked via comparison to new experimental results. The experimental system is composed of a 0.395 porosity, 5.35 μ2 synthetic sandstone and a 0.244 porosity, 0.686 μ2 natural sandstone. The cores are arranged in parallel and communicate through common injection and production conditions. Nitrogen is the gas phase and a classical alpha-olefin sulfonate (AOS 1416) in brine is the foamer. Three types of experiments were conducted. First, gas alone was injected into the system after presaturation with the foamer solution. Second, gas and foamer solution were coinjected at an overall gas fraction of 90% into cores presaturated with surfactant. Each core accepted a portion of the injected gas and liquid according to the mobility within the core. Lastly, gas and foamer solution were coinjected into the individual, isolated porous media in order to establish baseline behavior. The results show that in-situ generation of foam is an effective method for improving the sweep efficiency of lower permeability strata. The results also confirm predictions that foamed gas can be more mobile in lower permeability porous media.
Reservoir Management of the El Furrial Field – Venezuela under Enhanced Oil Recovery Process
Authors: Araque Isaura Echeverría , Auxiette S. A. Gerard
Published: December 2007

El Furrial field, is located in the north of Monagas State and was discovered in 1986. It originally contained around 7.5 billions STOIIP. The field is approximately 13 km long and 7 km wide. It produces from two main formations identified as the Naricual and Cretaceous Formations. The gross thickness of the two reservoirs is more than 2100 ft. The oil composition in the Furrial Field changes rapidly with depth from that of a conventional oil (28 °API) at the top of the formation to that of an immovable tarmat, at the base of the reservoir. Mainly as a result of the increasing asphaltene content of the crude.

PDVSA has devoted intensive engineering studies to define the optimum development strategy and to maximise final recovery. As a result of these studies, production mechanisms were identified early and a reservoir pressure maintenance program was defined to increase the recovery and to sustain production. Simultaneously with the implementation of a waterflood project, engineering studies were continued to determine the feasibility of a gas-injection alternative. These studies showed that complement to the water-injection program and it will increase cumulative oil recovery by around 7.5 % OOIP.

Additional mechanistic studies concerning the WAG process for the downdip flanks have been done. The results from these shows increase in the recovery factor by about 7 to 10 % OOIP, due to the miscible gas effect.

The studies involve, extensive laboratory work, geostatistical and deterministic reservoir descriptions and cross-sections compositional and black-oil miscible simulation models, to define the best recovery process. At this moment water and gas injection processes are already implemented and are at present injecting about 458 MBWPD and 393 MMSCFD. A mechanistic WAG pilot project is ongoing.
Alternatives of Gas Injection as an Enhanced Recovery Method in Advanced Gas Market Environment
Authors: Palasthy G. , Kristof P. , Tóth T.
Published: December 2007

In Hungary, the oil prices in the range of $20 makes EOR projects commercially viable. Because of their structures and fluid properties, the oil reservoirs in Hungary are suitable for gas injection EOR methods. This EOR potential is well supported by favourable infrastructure in the local oil industry/surroundings.

The paper presents the EOR application for a large reservoir in the Pannonian basin. The Szeged-Móravóros is undersaturated fractured reservoir with Triassic dolomite, Miocene sandstone and conglomerate at the depth of 2630-2450 meters below the sea level. The OOIP derived from material balance is 11.56 million cubic meter and oil gravity is 817 kg/m3.

The initial pressure was pr=331 bar, initial temperature was tr=140 °C. In the period of the natural depletion between 1975-1980, the cumulative oil production was 1,27 million cubic meter. In this period, because of the limited water influx, the reservoir pressure dropped below the bubble point and secondary gas cap started to increase. The pressure dropped to pr=244 bar.

In 1980, water injection was started to maintain the reservoir pressure. The aim was to increase the reservoir pressure above the bubble point pressure. With this water injection from 1980 to the present time, the oil recovery is 36.4 % with a cumulative oil production of 4.21 million cubic meter. The current reservoir pressure is 250 bar.

For studying the further recovery enhancement, laboratory and reservoir simulation studies were carried out to evaluate different gases. Natural gas, nitrogen, and CO2 were selected for the gas injection near the structure top. In Hungary, large CO2 reserves are available 50-250 km distance from the oil field. The natural gas resources are easily available because of the developed gas distribution network and the production of nitrogen by stripping from the air can be also easily realised. At the optimal pr=250 bar pressure, the displacement process is not miscible in the reservoir, and the recovery increment is not sensitive to the type of injected gas or its quality. The reservoir simulation shows the recovery increment is about 12 %.

We have selected nitrogen gas as an injection gas based upon economic and environment evaluations. The paper describes how we arrived at this conclusion in a country where there is a well-developed natural gas market. The paper also includes discussion about the methods and criteria used to select the process.
Multi-Scale Iterative Techniques and Adaptive Mesh Refinement for Miscible Displacement Simulation
Authors: Trangenstein John A. , Bi Zhuoxin
Published: December 2007

Many enhanced oil recovery processes in reservoir engineeringinvolvelocalized phenomena that could be due to several features, such asinjection fronts, wells or reservoir heterogeneity.In order to reach sufficientaccuracy in field-scale simulation, the localized phenomena need to be resolvedand modeledin appropriate scale-dependent ways.Our approach to treating thelocalized phenomena is to usehigh-resolution discretization methods incombination with dynamicallyadaptive mesh refinement(AMR).The purpose ofadaptive mesh refinement is to concentrate thecomputational work near theregions of interest in the displacement processes, which may evolve constantlyin space.Adaptive mesh refinement requires appropriate techniquesfor datacommunication in a hierarchy of dynamically adaptive mesh.The selection ofappropriate scaling rules as well as computationallyefficient data structuresis essential to the success of the overallmethod.

We have exploited the object-oriented features of C++ for the AMR programstructure and data management, while numerically intensive routines areimplemented in FORTRAN.It turned out that adaptive mesh refinement cansignificantlyreduce the computational cost required to obtain a desired levelofaccuracy in the simulation.However, the emphasis here is on the developmentof efficienttechniques for solving linear systems that arise in thenumericaldiscretization of an elliptic equation for the incompressiblepressurefield. We use a conjugate gradient algorithm preconditioned bymultiplicative domain decomposition between refinement levels, in whichadditivedomain decomposition and incomplete Cholesky factorization were employed as"smoothers".In this paper, the combined adaptive mesh refinement technique hasbeenapplied to a single-phase tracer transport model for miscibleflooding.Numerical results demonstrating the effectiveness of the methodarepresented and discussed.
Simulations of Chemical and Microbial Enhanced Oil Recovery Methods
Authors: Delshad Mojdeh , Asakawa Kazuhiro , Pope Gary A. , Sepehrnoori Kamy
Published: December 2007

Our chemical flooding simulator UTCHEM has been under development for many years and continues to evolve as a general purpose chemical simulator. We have extended the capability of this simulator to process advanced oil recovery methods which use surfactant, polymers, gels, alkaline chemicals, foam, and microorganisms as well as various combinations of these. We have developed and implemented a multiphase and multicomponent dual porosity model so in addition to targeting conventional oil reservoirs, the use of chemical methods in naturally fractured oil reservoirs can be evaluated. The model includes complex chemical phenomena previously modeled with UTCHEM for both fracture and matrix, e.g. the effects of reduced interfacial tension on phase trapping, surfactant adsorption, and so forth. In this paper we only discuss the dual porosity, foam, and microbial enhanced oil recovery models recently developed and implemented in UTCHEM.
An Effective Continuum Model for the Gas Evolution in Internal Steam Drives
Authors: Tsimpanogiannis Ioannis N. , Yortsos Yannis C.
Published: December 2007

We derive an effective continuum model to describe the nucleation and subsequent growth of a gas phase from a supersaturated liquid in a porous medium, driven by heat transfer. The evolution of the gas results from the reduction of the system pressure at a constant rate. The model addresses two stages before the onset of bulk gas ow, nucleation and gas phase growth. The problem arises in internal steam drives, for example of the type recently discussed in blowdown experiments in carbonate rocks (Dehghani et al., 1997, Dehghani and Kamath, 1999).

Important quantities characterizing the process, such as the fraction of pores that host activated sites, the deviation from thermodynamic equilibrium, the maximum supersaturation in the system and the critical gas saturation depend crucially on the nucleation characteristics of the medium. We use heterogeneous nucleation models in the form of pre-existing gas, trapped in hydrophobic cavities to investigate the nucleation behavior. Using scaling analysis and a simpler analytical model we show that the relevant quantities during nucleation can be expressed in terms of a simple combination of dimensionless parameters, which include rate effects. The subsequent evolution of the gas phase and the approach to the critical gas saturation are also described using numerical and analytical models.

The theory predicts that the maximum supersaturation in the system is a weakly increasing function of the decline rate. This function depends sensitively on the probability density function of the nucleation cavity sizes. It also predicts that the final nucleation fraction, thus the critical gas saturation, is a power law of the decline rate. The theory for both nucleation and phase growth is then compared with available experimental data and a good match is obtained by appropriate fitting of the nucleation characteristics of the medium.
Modeling of the Unusual GOR Performance in a Fractured Gas-Condensate Reservoir
Authors: Ghorayeb K. , Firoozabadi A. , Anraku T.
Published: December 2007

The Yufutsu gas-condensate field in Hokkaido, Japan, is an unusual reservoir. The fluid in the reservoir is heavier at the top, and the C7+ fraction decreases with depth despite pressure communication. Another unusual aspect of the reservoir is the decrease of the GOR from an initial value of around 1350 vol/vol to around 950 vol/vol in the first five years of production. In this work, we present the results of compositional simulation. The simulation is based on the initialization from a model that takes into account molecular, pressure, and thermal diffusion. The GOR predicted from the compositional simulation is in agreement with measured GOR.
Waterflood Prediction Of Partially Depleted Reservoirs
Authors: Higgins R.V. , Leighton A.J.
Published: December 2007

Publication Rights Reserved

This paper is to be presented at the California Regional Meeting of the Society of Petroleum Engineers of AIME in Santa Barbara, Calif., on Oct. 24–25, 1963, and is considered the property of the Society of Petroleum Engineers. Permission to publish is hereby restricted to an abstract of not more than 300 words, with no illustrations, unless the paper is specifically released to the press by the Editor of JOURNAL OF PETROLEUM TECHNOLOGY or the Executive Secretary. Such abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in JOURNAL OF PETROLEUM TECHNOLOGY or SOCIETY OF PETROLEUM ENGINEERS JOURNAL is granted on request, providing proper credit is given that publication and the original presentation of the paper.

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 considered for publication in one of the two SPE magazines with the paper.

A method is presented to calculate the performance of waterfloods which are started when the oil saturation is high and enough gas still remains in the reservoir oil to affect appreciably the rate of oil recovery. The interest in this type of flooding stems from the rapid recovery compared to waterflooding after depletion by the expansion of the dissolved gas. The quick recovery influences the rate of return on the investment.

The predictions for five-spot or other pattern floods are obtained by summing the performances of the individual channels bounded by streamlines obtained from the potentiometric model for the pattern. The times and rates are calculated using the shape factors and volumes determined from the equipotentials and streamlines of the potentiometric model. The recovery calculations at all times include the changing oil, water, and gas saturations throughout the pattern as influenced by the oil, water, and gas permeabilities and the quantity of water that has been injected. The recovery as a function of time is determined by the progress of an oil bank created by the injected water and a second downstream oil bank formed by the displaced gas. The flow of oil and gas in the second oil bank is governed by the permeabilities to oil and gas in this section.

Several examples are presented in order that engineers may ascertain the relative order of the effect of time, recovery, and rates as functions of the viscosity of reservoir oil, initial gas saturation, and distance between wells. The data for the linear and five-spot patterns are presented.

By the use of the high-speed digital computer, a performance calculation can be made in about 1–1/2 minutes.
Underground Combustion Oil-Recovery Experiment In The Venango First Sand, Warren County, Pa.
Authors: Caspero N.A. , Wertman W.T. , Eckard W.E.
Published: December 2007

A thermal oil-recovery experiment was conducted in the Venango First sand, Goodwill Hill oilfield, Warren County, Pa., about 10 miles northeast of Titusville. The Quaker State Oil Refining Corp., Bradford, Pa., performed the experiment with assistance from Sinclair Research, Inc., Tulsa, Okla., and the Federal Bureau of Mines.

The Goodwill Hill field was discovered in 1885. Primary-production operations continued until 1930 when an air-gas injection project, which is still in operation, was started. At the location of the combustion experiment, the reservoir is 400 feet deep and 30 feet thick, with wide permeability and porosity variations. The crude oil is typical Pennsylvania Grade paraffin-base oil with a gravity of 43.9 API and a viscosity of 4.55 cp at 60 F.

The well pattern for the experiment consisted of 5 producing wells, enclosing an area of 1.28 acres, and a central ignition-injection well. An air-natural gas mixture was ignited in the ignition well on July 29, 1961. Ignition was followed by injection of air and natural gas at various rates. The experiment was suspended January 5, 1962, when it became evident that economic oil production could not be achieved.

There was no conclusive evidence that self-sustained combustion was achieved or that combustion increased oil and water production. A slight increase in liquid production was attributed to stripping action caused by the air-injection rates, which were higher than those normally used during air-gas injection.
The Evaluation of Specialized Cements
Authors: Butsch R. J. , Morris C. W. , Wydrinski R. , Kasecky M. J.
Published: December 2007

In recent years specialized cements have been developed for use in the oilfield. These cements have ranged from very lightweight to very heavy cements. They have included additives such as glass or ceramic beads to alter their properties. With an increased use of these cements, concerns have risen about the cement evaluation. Quite often the question is asked, "Can we evaluate these cements?" rather than, "How do we evaluate these cements?" This paper will discuss some logging techniques that can be used to evaluate these new cements.

The desire to cement longer casing intervals without exceeding the formation fracture gradient has led to the use of very light weight cements. These cements have low acoustic impedance values that are not much higher than the acoustic impedance values of drilling fluids. The compressive strength of these cements can also vary significantly. Acoustic impedance and compressive strength are the properties that cement evaluation tools use to differentiate between the fluids and the solids in the casing formation annulus. To identify these differences it is critical that the proper logging techniques and input parameters are selected for the sonic and ultrasonic tools. A statistical analysis of acoustic impedance measurements from the ultrasonic tools has also proven to be valuable for the evaluation of these special cements.

Examples from Alaska, and other areas where these types of cements are being used to solve difficult completion problems, will be shown to demonstrate the use of these cement evaluation techniques.
Practical Applications of NMR Technology Enhance Formation Evaluation, Testing and Completion Decisions
Authors: Davis Bob , McDonald Tom , Aly Mohamed
Published: December 2007

In the last several years the use of borehole nuclear magnetic resonance (NMR) measurements has become more commonplace because the measurements are better understood by the service and operating companies and new applications have been developed. In most wells drilled in Indonesia, basic formation evaluation tools deliver sufficient data for evaluation. However, some wells can be more difficult to evaluate for any number of reasons. NMR measurements provide new petrophysical parameters that can help deal with difficulties such as low-contrast pay resulting from high irreducible water saturation or iron-rich minerals, varying or unknown formation water resistivity, and unknown mineralogy and grain density. Any of these issues can lead to inaccurate evaluations.

Producibility is another issue that standard logs are not designed to address. Determining this property often requires drillstem tests or tests made with wireline formation testers. NMR measurements can give a cost-effective, continuous quantitative indication of rock quality and permeability in lieu of these tests.

This paper will present several case studies from wells in Sumatra and Java where the basic NMR measurements have been used by asset teams to solve difficult evaluation problems. The NMR measurements have been integrated into a full volumetric evaluation of the reservoirs. These examples will cover clastic, carbonate and basement (weathered granite) formations. Production, test results and core analyses have been used to validate the evaluations.
Turn Down the Burner: Impact of Heat Management on the Potter Reservoir, MWSS Field, California
Authors: Fram J. H. , Dailey W. H. , Walker C. J.
Published: December 2007

In November, 2000, prompted by extremely high natural gas prices, steam injection was reduced by 78,000 BSPD (60%) for an extended period in the Potter Reservoir of the MWSS Field located in California. The price environment served to accelerate efforts to reduce injection to the thermodynamic minimum. Production decreased by around 5000 BOPD (SOR ~ 18:1). The Potter formation is a steeply, dipping sandstone reservoir containing 13° API oil and has been under thermal recovery for over 30 years. An extensive surveillance network of observation wells allowed for gathering of high quality heat and reservoir fluid information.

This paper will discuss the theory and approach taken to set lower steam targets. It will also show examples of the impact of lower steam rates on thermally mature properties. Additional unresolved issues concerning our current inability to fully understand the relationship between reservoir (or steam chest) temperatures and oil production rates will also be discussed.
A Simulation Study of Novel Thermal Recovery Methods in the Ugnu Tar Sand Reservoir, North Slope, Alaska
Authors: Sharma Bakul C. , Khataniar Santanu , Patil Shirish L. , Kamath Vidyadhar A. , Dandekar Abhijit Y.
Published: December 2007

The Ugnu reservoir, located in the Kuparuk River Unit on the North Slope of Alaska, is estimated to contain over 6 billion barrels of heavy oil in the form of tar and bitumen. Due to the extreme oil viscosities conventional enhanced oil recovery (EOR) methods are not readily applicable to the Ugnu sands. Additionally, high reservoir heterogeneity creates complications with EOR processes. A detailed simulation study was conducted to evaluate the performance of four novel thermal recovery methods in the Ugnu reservoir. These methods included steam assisted gravity drainage (SAGD) with horizontal injectors, SAGD with vertical injectors, SAGD with electrical preheating (EP-SAGD), and EP-SAGD with vertical injectors. A conventional steamflood was also simulated for comparison as the base case. The effects of various reservoir and process parameters such as well spacing, flood pattern, reservoir heterogeneity, and anisotropy on process performance were studied. The four SAGD based processes were found to be far superior to conventional steamflood, which performed very poorly. An optimum spacing between injector and producer for SAGD methods was determined. The EP-SAGD process was found to be thermally more efficient than SAGD, however, final oil recoveries were comparable for the two methods. Placement of horizontal producer was found to be more critical than placement of the injector.
Improved Means of Reducing Drag in ERD Applications
Authors: Fuller Andrew , Jardaneh Kamal
Published: December 2007

The increasing number of difficult Extended Reach Drilling (ERD) applications in recent years has emphasized the need for reducing drill string drag. Drill string drag can substantially limit weight on bit and negatively effect directional control.

An improved type of drill pipe deployed Non-Rotating Drill Pipe Protector (NRDPP) has been developed that was found, both in laboratory tests and in actual down-hole drilling/sliding applications, to reduce drag inside casing up to 50% of that for bare drill pipe. This new tool incorporates existing NRDPP fluid bearing technology for torque reduction along with a modified geometry and the use of low-friction wear pads to reduce drag.

This paper describes the design and testing of the new "Low-Drag" NRDPP and provides a detailed discussion of three different wells that were drilled using this new tool for the purpose of providing drag, torque, and casing wear reduction. The wells, drilled by major oil companies in different regions of the world, were of varying profiles and possessed a unique set of operational circumstances.
Cheaper Cement Formulation for Lost Circulation Control
Authors: Samsuri A. , Phuong B. T. N.
Published: December 2007

Laboratory experiments had been carried out by using G and special blended cement with various amount and types of standard cement additives, and various amount of local bentonite and sugar cane fiber. The ASTM-C 114 and AAS procedures were used for the chemical analysis and API Spec. 10 procedures under atmospheric and reservoir conditions for the cement performance.

One of the serious cementing problems is a lost circulation, which may occur in high permeability formation, vugs or naturally fractured formation. Therefore this study focused on development of a cement mixture to overcome lost circulation problem and also strong enough to hold casing with minimize damage to potential producing formation. The results shown that optimum size of local bentonite ranging from 150-250μm and sugar cane fiber ranging from 2000-2800μm. A suitable cement system formulation for optimum lost circulation control is 9% local bentonite, 2% calcium chloride, and 0.5 sugar cane fiber with adequate shear bonding strength and formation permeability reduction is about 10%.

Generally, special blended cement has less free water and fluid loss, better strength development but shorter thickening time than G cement. The cost of blended cement is cheap, bentonite is a local material and sugar cane fiber is a waste material, therefore there will be about 48% of the cement material cost saving if this cement formulation is used for an average oil well at 8,000 ft depth. This formulation also proves to be the cheaper choice for cementing job, particularly the shallow well due to the shorter thickening time.
A New Wellbore Position Calculation Method
Authors: Chia C. R. , Phillips W. J. , Aklestad D. L.
Published: December 2007

A method is described for combining multiple wellbore surveys to obtain a single composite, more accurate, well position. Established methods for defining the wellbore position, and its associated uncertainty, rely upon accepting the position obtained from the most accurate survey instrument used in each section of the wellbore. This position is then assigned an uncertainty based on the information from this single survey instrument run. Today, when a modern wellbore is constructed, each section may be surveyed for position many times using one or more magnetic, gyroscopic or inertial survey instruments. By statistically combining the wellbore positions obtained from all of the survey instruments run in a given section of the wellbore a new position, designated the ‘Most Accurate Position’ (MAP), is calculated. The main advantage of the MAP is that its uncertainty is smaller than the uncertainty of any of the constituent surveys. The major benefits of this technique will be to facilitate the drilling of smaller targets at greater distances, allow the drilling of new wellbores in closer proximity to existing wellbores while maintaining accepted safety clearance rules, and improved reservoir delineation.
Technical Developments in Modular Rig Design - Lowering Operator Costs
Authors: Carter Greg J.
Published: December 2007

Modular workover and drilling platform rigs have played an important role in the development of existing oil and gas fields since the 1960’s. The past decade has seen tremendous design improvements in both workover and drilling operations. Improvements range from effective utilization of top drives for sidetracking and extended reach programs to minimizing weight and space distribution of the rig to accommodate minimal space platforms. Case history studies will illustrate how technological developments in modular rig design have increased an Operator’s invested return on their offshore platforms and hired drilling/workover rigs.
The Development of a New Generation of Nitrogen Membrane Unit Will Allow Greater Flexibility and Wider Operational Applications In Offshore Applications
Authors: Pia Giancarlo , Fuller Tom , Allen Tim
Published: December 2007

As underbalanced drilling and intervention operations find offshore applications, development may be restrained by physical dimensions, operational delivery and logistics preventing the wider application of the technology and maintaining the conventional methods with its higher cost base.

The first generations of Nitrogen Membrane units were large stand-alone skids that had no built-in compression and booster capability; these were supplied in separate units. For land-based use in drilling, well intervention and pipeline applications, this presented no problems since space availability was not an issue. However for offshore use where space is at a premium, these additional components presented such a large footprint that their use was difficult in most applications and impossible for smaller jack-up rigs and production platforms, where deck space and loading are major limitations.

In order to facilitate the use of Nitrogen Membrane technology in offshore environments, it was clear that a new generation of units would be needed. Initial development centered on existing land-based units, with primary and booster compression, Membrane and cooling combined in modular two-piece units. This approach provided for a smaller footprint, but lower output per square foot of space occupied and higher individual weights. This output penalty could be made up with additional units but the space occupied was prohibitive. Subsequent development efforts were based on a three-piece unit with prime mover, primary compressor and secondary booster driven in-line through a single drive shaft. A second-generation Nitrogen Membrane unit, with increased output and efficiency, and the cooler skid, were top-mounted on the three-piece unit. A third generation unit is currently in the design and development stage, which will be fully compliant with all offshore regulations for North Sea operations.

This paper will review the existing technology of Nitrogen Membranes. It will detail the development and design of the second and third generation units on which all the major concerns such as performance per weight/area, access, zone and operator compliance requirements and safety were addressed. It will also review all the stages of the developments, the design, manufacture, testing and field problems encountered and the lessons learned from them.

Some wider application of the technology will also be demonstrated due to the improved technology and the cost savings through operational efficiency highlighted.
An Innovation in Designing Underbalanced Drilling Flow Rates: A Gas-Liquid Rate Window (GLRW) Approach
Authors: Guo Boyun , Ghalambor Ali
Published: December 2007

Underbalanced drilling (UBD) has gained strong momentum in recent years because of a number of advantages of the technology including reduced formation damage and minimized lost circulation. Due to the complex nature of water, oil, gas and solid multiphase flow in the UBD systems, numerous runs of sophisticated computer programs are required to draw the boundary of the safe gas -liquid rate envelope. It is highly desirable to have a simple and reliable procedure to perform optimum UBD designs.

This paper describes an innovative procedure to delineate the boundary of the safe gas -liquid rate envelope for UBD flow rates. In developing the safe gas-liquid rate envelope, formation fluid pressure limits the upper bound of the flowing bottom hole pressure and wellbore collapse pressure serves the lower bound of the circulation-break bottom hole pressure. The envelope is closed with boundaries determined by fluid’s cutting carrying capacity and wellbore washout criteria. Detailed procedure for the development of the safe gas-liquid rate envelope using a spreadsheet program is described in the paper. A successful field UBD case is reviewed and compared with the safe gas -liquid rate envelope. This work provides drilling engineers and drilling supervisors an easy-to-use approach to designing and mo difying gas and liquid injection rates in UBD. The safe gas-liquid rate envelope can also be used for evaluating feasibility of UBD under given geological conditions.
Drilling Knowledge Management, What is Missing and Can We Fix it?
Authors: Irrgang Rosemary , Kravis Simon , Nakagawa Edson
Published: December 2007

Although knowledge is predicted to surpass oil and gas reserves as the most important asset in 21st century oil and service companies, engineers remain cynical about the benefits of current knowledge management initiatives. This paper discusses problems such as the strong bias of existing knowledge management systems in favour of document searching and focuses on how overlooked areas can be addressed. Results of a collaborative project with 5 major oil companies aimed at overcoming some important limitations of current knowledge systems are discussed. A key feature of the initiative is software to integrate knowledge capture and reuse into normal work processes. The software uses well data and stored drilling experiences, including problems and solutions, from a global drilling and completions database provided by the member oil companies. Experiences with deployment of this software into oil companies will be covered as well as the results of research projects on automated learning and case based reasoning to enhance the company knowledge base for optimal design of new wells. The study of overall well quality has also been included in the project. By defining well quality metrics and then examining them collectively, we can better assess drilling performance in a given field, and ascertain if the company is using its knowledge to improve new well production and cut costs.
Wet Gas Venturi Metering
Authors: Stewart David G. , Brown Gregor , Hodges David
Published: December 2007

Multiphase metering is becoming increasingly important in the development of marginal oil and gas fields. Many of these fields are only economically viable if they can be tied back to existing platform infrastructure, reducing the capital expenditure required by significant margins. In such cases, several fields are often tied back to common facilities requiring each unprocessed stream to be metered before co-mingling.

Multiphase metering is also a valuable technology in well management, providing on-line information on the production flow; and in well testing, reducing the capital expenditure required to investigate potential new wells.

Wet gas metering is at the high gas fraction end of multiphase metering, typically with a gas volume fraction (GVF) above 90%, and mostly above 95%. Standard multiphase meters cannot operate satisfactorily in such conditions. The development of Wet Gas Meters is therefore a key requirement of the oil and gas industry.
Borehole Stability in Naturally Deformable Fractured Reservoirs - A fully coupled approach
Authors: Zhang Jincai , Roegiers Jean-Claude
Published: December 2007

A dual-porosity fully coupled finite element solution has been developed to model inclined wellbores drilled in naturally deformable fractured media. Four kinds of borehole failure criteria were assumed to describe the reservoir rock behavior. Several application cases were examined for mud weight selections for holes drilled in normal and tectonic stress regimes. Upper and lower bounds as well as most stable borehole orientations were determined. The optimum trajectory of horizontal boreholes was discussed. Furthermore, the stability of a borehole intersecting a weak zone was analyzed.
Deep Water Drilling Performance
Authors: Avignon B. , Simondin A.
Published: December 2007

Since 1967, TOTALFINAELF has been actively involved in deep water drilling operations but the saga really began in 1976 with the building of the PELERIN drill ship which broke a first water depth world record by drilling a well in 925 m of water offshore Algeria. This was followed by another outstanding performance in 1982 when TFE drilled the first well in a water depth greater than 1500 m (1714 m, in the Mediterranean sea). Following these campaigns, there was a lull in deepwater drilling that lasted about ten years.

However, in 1994 the exploration Offshore Angola on the bloc 17 re-activated the group drilling activity in deep waters. Since this time, 62 wells have been drilled in water depth ranging from 500m to 2851 m in Angola, Congo, Gabon, Equatorial Guinea, Nigeria, Brazil and in the GOM. The majority of those wells are challenging exploration or appraisal wells, for which core have been cut in nonconsolidated sands, sand control completion have been run and DST have been performed. Twelve wells are development wells, which have involved installation of subsea completions. All types of rigs have been used from moored semisubmersible, old DP drill ships, to new built semi-submersible and drill ships including two types of dual derrick units.

Those drilling performances leaded to the production start up of the Girassol field by 1400m of water on the 04th of December 2001 with some wells producing over 30,000 BOPD. It will shortly (summer 2002) lead to the start up of the Aconcagua gas field, which is the deepest field ever completed (2200 m of water).

This huge amount of deep water well operations brought a lot of data and experience, the purpose of this paper is to show what type of drilling and completion performance one can expect according to the type of well to be drilled. The paper will compare drilling operations durations achieved for dry hole wells with appraisal wells, including heavy data acquisition program. The type of rig will be analysed with in particular the gain one can expect by using dual derricks drilling rigs. Alternative solutions to conventional Subsea drilling such as surface BOP stack, slender wells will also be discussed.