bluuebunny/crossref_metadata_2025 huggingface dataset:
Air-Injection EOR in Highly Water-Saturated Light-Oil Reservoir
Authors: Teramoto T. , Uematsu H. , Takabayashi K. , Onishi T.
Published: December 2007

Since 1950s In-Situ Combustion (ISC) has been applied to mainly heavy-oil reservoirs. In recent years, High Pressure Air Injection (HPAI) which is a displacement process categorized as ISC, is applied to light-oil reservoirs. And it has proven to be a valuable Enhanced Oil Recovery (EOR).

Reduction of oil viscosity is very important for ISC process. In contrast, it is not so essential for HPAI because original viscosity of light-oil is not as high as that of heavy oil. HPAI is considered as flue gas injection, since a flue gas sweep is one of the most important recovery factors of HPAI. However a flue gas sweep recovery factor is not effective for highly water saturated light-oil reservoirs, while thermal effects become an important recovery mechanism.

This paper discribed the feasibility study of HPAI for watered out light-oil reservoirs, oil recovery mechanism and several simulation studies to establish maximum oil recovery factor.

For the feasibility study, Combustion Tube tests (CT tests) and simulation studies were conducted. The oil recovery was observed in the CT test with crushed core which was flooded out by water. This result suggests that HPAI can be applied to highly water saturated light-oil reservoir. The results of simulation studies also indicate its feasibility. They also made clear that distillation process that was one of thermal effects of HPAI was a main recovery factor for a HPAI in this case.

In order to maximize the oil recovery, controlling a channeling of injected air is important because early breakthrough of the air reduces oil production period significantly. The results of our studies show that not only a design of well completion but also an adjustment of air injection rate enable to increase vertical sweep efficiency and that line drive injection is effective to increase areal sweep efficiency.
Theoretical and Practical Aspects of Tertiary Hydrocarbon Migration
Authors: Minescu F. , Popa C. , Grecu D.
Published: December 2007

Primary and secondary migrations are well defined terms in hydrocarbon reservoir genesis. Both of them designate spontaneous displacement of the hydrocarbon, from the source rock to the final trap, i.e. to the reservoir rock.

Producing the reservoir implies a forced movement of hydrocarbons towards the wells, consuming the energy accumulated over the ages.

Mainly due to the gravitational forces and water influx, a new kind of fluid movement is taking place into the reservoir towards its production final stage. The main feature of the fluids displacements into the reservoir is their spontaneous character. This kind of fluid movement that occur after reservoir abandonment, defines the tertiary migration process.

As a consequence of tertiary migration, the reservoir fluids, water, oil and gas, tend to place themselves to a normal-gravitational position. Additionally, the dynamic pressure distribution at the end of the production history tends to relax, amplifying the migration process towards normal stationary pressure gradients. The result of the tertiary migration is a new saturation distribution into the reservoir and it is expected that in the most favorable cases, the production potential of some parts of the reservoir should be restored.

From this point of view, an enormous interest for Romania concerns the old oil reservoirs, abandoned over 7080 years ago with a final recovery factor sometimes less then 20%.

The present paper examines the principles and factors involved in the tertiary migration process. A special attention is paid to pressure redistribution and gravitational segregation during such a process. To demonstrate the concept, this study discusses two successful production restarting projects in Romania. If today the world is not very proud about production restarting projects, tomorrow will be for sure.
Integration of Volumetric and Material Balance Analyses Using a Bayesian Framework To Estimate OHIP and Quantify Uncertainty
Authors: Ogele C. , Daoud A. M. , McVay D. A. , Lee W. J.
Published: December 2007

Estimating original hydrocarbons in place (OHIP) in a reservoir is fundamentally important in estimating reserves and potential profitability. Two traditional methods for estimating OHIP are volumetric and material balance methods. Probabilistic estimates of OHIP are commonly generated prior to significant production from a reservoir by combining volumetric analysis with Monte Carlo methods. Material balance is routinely used to analyze reservoir performance and estimate OHIP. Although material balance has uncertainties due to errors in pressure and other parameters, probabilistic estimates are seldom generated.

In this paper we use a Bayesian formulation to integrate volumetric and material balance analyses and to quantify uncertainty in the combined OHIP estimates. Specifically, we apply Bayes’ rule to the Havlena and Odeh material balance equation to estimate original oil in place, N, and relative gas-cap size, m, for a gas-cap drive oil reservoir. We consider uncertainty and correlation in the volumetric estimates of N and m (reflected in the prior probability distribution), as well as uncertainty in the pressure data (reflected in the likelihood distribution). Approximation of the covariance of the posterior distribution allows quantification of uncertainty in the estimates of N and m resulting from the combined volumetric and material balance analyses.

Our investigations show that material balance data reduce the uncertainty in the volumetric estimate, and the volumetric data reduce the considerable non-uniqueness of the material balance solution, resulting in more accurate OHIP estimates than from the separate analyses. One of the advantages over reservoir simulation is that, with the smaller number of parameters in this approach, we can easily sample the entire posterior distribution, resulting in more complete quantification of uncertainty.
Comparison and Investigation of Recovery Factor From Simulation of Water and Gas Injection in One of the Fractured Reservoirs in the South of Iran
Authors: Sobhi G. , Kiani M. , Alizadeh N.
Published: December 2007

Most of the oil production in the Middle East comes from carbonate reservoirs, the majority of which are fractured. These reservoirs tend to produce at high rates in their early production period followed by low rates later on, leading to low overall recovery. The challenge is to manage the field and arrest the production decline for a long time.

A reservoir simulation study was performed on a fractured Middle Eastern carbonate field to determine the optimal production strategy. Three possible scenarios – natural depletion, gas injection and water injection were compared. Results indicated that water injection yields better recoveries than gas injection and natural depletion; this is expected since the rock is intermediate to oil-wet, meaning that there was high recovery from imbibition in water flooding. The presence of connected fractures led to early breakthrough and low recoveries in gas injection scenarios. The different physical mechanisms affecting oil recovery are discussed and recommendations are made for other fields with the same fracture properties and wettability
Innovative Approach for Automatic Real-Time Monitoring of the Fluid Level in Wells Without Returns to Surface During Workover Operations—A Successful Field Test
Authors: Pattay P. W. von , Strasser R. , Seitzjef A.
Published: December 2007

Today, mature fields are a major interest for many oil companies since their un-recovered potentials are expected to help satisfy the worlds growing oil demand. However, while operating in such fields companies face new challenges.

As such, many mature fields show under-hydrostatic reservoir pressure due to depletion, which might lead to no returns to surface during workover operations. No returns to surface make it impossible to recognize any losses as an indicator for potential formation damages or gains as an indicator for a potential kick.

The crucial question is therefore how to recognize losses or gains in real time without returns to surface during workover operations?

Knowing the depth of the fluid level in the well at any point in time would allow recognizing losses and gains, simply by monitoring all the changes of the fluid level in the well.

This paper presents a newly developed measurement approach using a specially designed echometer that allows monitoring the fluid level in the well without returns to surface during workover operations automatically in real time, which is a fundamentally new application for an echometer.

All the technical requirements that were identified to be critical for this measurement approach are highlighted in the paper. Further the paper lines out all the associated technical challenges that were faced while implementing this measurement approach. Finally, reliability and functionality of the measurement approach were proven in a series of field tests under various operational conditions.
Permeability Determination of the PL19-3 Field for Geologic Model Input
Authors: Fetkovich M. D. , Gerard M. G. , Chin L. Y. , Shuxing D.
Published: December 2007

The overall structure of the PL19-3 field, which is located in Bohai Bay, is an asymmetrical wrench anticline that formed by a combination of differential subsidence, strike-slip faulting, and normal faulting. Faults form the main trapping components for the individual hydrocarbon-bearing fault blocks. The reservoir sands of the deeper Guantao formation are dominantly braided fluvial sandstones, while the shallower Minghuazhen formations are dominantly meandering fluvial sands. Fault blocks penetrated by appraisal or development wells tested oil with viscosities ranging from 10 to 380 cp. Multiple vertically separate pressure systems exist in each fault block.

The purpose of this paper is to present a case history that demonstrates multiple methods used to calculate permeability for input into a fine grid geologic model and ultimately a flow simulation model. Special core analysis and facies description was used to generate facies-based permeability versus porosity relationships that can be used with log-calculated variables. Permeability log curves were calculated for each well in the field, and then input them into a geologic flow model. Pressure transient analysis was used to condition the facies based porosity versus permeability relationships to ensure that they matched actual well performance.

The permeability logs for all of the producing and injection wells were input into a flow simulation model. Comparisons of model predicted versus actual performance show close agreement. A good permeability estimate ultimately results in reasonable values of transmissibility, original oil in place, and sand connectivity. Advanced decline curve analysis was used as an additional method for calculation of kh, skin, and original oil in place (OOIP) and to validate model predicted performance matched actual transient, depletion, and waterflood performance behavior. In addition because this field contains reservoirs with unconsolidated sands the effect of stress dependent permeability was studied.
Multiscale Pore-Structure Characterization by Combining Image Analysis and Mercury Porosimetry
Authors: Han H. , Ioannidis M. , Dusseault M. B. , Xu B.
Published: December 2007

This article introduces a multiscale pore structure characterization method using a combination of mercury porosimetry and image analysis. The method was used to determine the distribution of pore volume by pore size and to estimate the pore-to-throat size aspect ratio. The key idea of the method is that pore size distribution obeys a fractal scaling law over a range of pore size. On this basis, scattering intensity data computed from the measured two-point correlation function and those measured from mercury porosimetry are extrapolated in the size range 0.01 μm < r < 1000 μm, using the known fractal scaling law.

A set of siltstone samples taken from Daqing Oilfield was analyzed through this method. Distribution of pore volume by pore size over the entire range of pore length scales was determined. The results demonstrated significant similarities in the pore structure of all samples. The image analysis results were in qualitative agreement with the results of mercury intrusion/extrusion tests.

The results were also compared with some other samples (including siltstone, sandstone, and dolomite) that had been analyzed using similar methods. It is shown that the surface fractal dimension obtained by analysis of MIP data is consistent with the value obtained by image analysis for different samples with different porosity and permeability.

Novel information on the pore-to-throat aspect ratio is obtained by comparing the complete pore volume distribution (PVD) to the MIP data.
The Valuation of the Multistage Investment in an E&P Project Using a Four-Fold Compound Option
Authors: Liu J. , Chen H. , Yang S.
Published: December 2007

This paper presents a model for valuing and the multi-stage investment in E&P project using N-fold continuous compound option formula. This model resolves the multi-stage investment decision problem, and extends the notion of a compound option to the n-fold compound option with time- dependent volatility and interest rate. It indeed presents additional insights into the creation of shareholder value of petroleum production and should therefore be used next to more traditional approaches such as Black-Scholes-Merton simulations, especially when tailored to the characteristics of real-life cases of E&P project development processes.
Failure Analysis of String Corrosion and Its Protection during Constructing and Operating Gas Storage Facility in Bedded Salt Deposit
Authors: Guangjie Yuan , Qinghua Wang , Ruichen Shen , Jinping Yuan , Lijun Lu , Chunmao Wang
Published: December 2007

With more and more salt cavern gas storage under construction, the corrosion problems of leaching string, production string, and production casing require more attention by experts o gas storage. This paper introduces several corrosion phenomena which are encountered during the operation of leaching salt caverns, and natural gas injection and withdrawal. The main corrosion factors are discussed such as brine, air, microbes, components of natural gas, gas injection velocity, operating status and others. The corrosion mechanisms are also analyzed. Inorder to prevent the corrosion effects a series of measures are applied successfully during different construction phases of the gas storage facility in the Yangtze River Delta, such as oxygen scavenger and biocide, coating protection, annulus protection liquid, cathodic protection.
Hydrate-Inhibited Scale Inhibitor for Use on Subsea Templates
Authors: Hills E. , Hase A. , Turner K. , Brice S. , Ross A. , Auflem I. H. , Saeten J. O.
Published: December 2007

An offshore Mid-Norway oil field includes wells on sub-sea templates at a depth of 350m. The formation waters contain up to 300 mgl−1 of barium, giving a sulphate scaling potential on seawater breakthrough. Scale protection on the template and down-hole is provided by squeeze treatments. Deployment possibilities include bull-heading down the methanol injection line (a distance of 10km) and bull-heading directly to the sub-sea template from a boat. In the event of a produced gas leak into the system, the conditions dictate that a water-based squeeze inhibitor will be in the region for hydrate formation. In such an event hydrates would be formed in minutes, blocking the service line before it could be re-flooded with the thermodynamic hydrate inhibitor methanol.

Current scale inhibitors (SI) are hydrate-inhibited by formulation in MEG. This paper describes an innovative SI protected from hydrate formation by formulating with kinetic gas hydrate inhibitors (KHI).

The field scale squeeze inhibitor was modelled and shown to have the potential for hydrate formation under sub-sea conditions. The concentration of MEG required to avoid this region was also modelled as >50% based on water. This was followed by laboratory autoclave tests when gas hydrates formed as predicted by the model. Using the same SI formulated with a small addition of a KHI the hydrate induction time was extended beyond the SI residence time in the injection line. Further testing of SI efficiency demonstrated an improved efficiency over an equivalent scale inhibitor formulated in MEG.

Due to the spiralling costs of installing new oil production facilities the use of sub-sea templates is increasing. Any scale squeeze treatments must be protected against potential gas hydrate formation. This paper describes such a protection by adding a KHI to a water-based product rather than formulating in MEG thereby allowing formulation at higher SI actives, potential lower costs and a lower viscosity product at low temperature.
Placement Using Viscosified Non-Newtonian Scale-Inhibitor Slugs: The Effect of Shear Thinning
Authors: Sorbie K. S. , Mackay E. J. , Collins I. R. , Wat R.
Published: December 2007

Reservoir formations are often very heterogeneous and fluid flow is strongly determined by their permeability structure. Thus, when a scale inhibitor (SI) slug is injected into the formation in a squeeze treatment, fluid placement is an important issue. To design successful squeeze treatments, we wish to control where the fluid package is placed in the nearwell reservoir formation. In recent work1, we went "back to basics" on the issue of viscous SI slug placement. That is, we re-derived the analytical expressions that describe placement in linear and radial layered systems for unit mobility and viscous fluids. Although these equations are quite well known, we applied them in a novel manner to describe scale inhibitor placement. We also demonstrated the implications of these equations on how we should analyse placement both in the laboratory and by numerical modelling before we apply a scale inhibitor squeeze. An analysis of viscosified SI applications for linear and radial systems was presented both with and without crossflow between the reservoir layers.

In this previous work, we assumed that the fluid being used to viscosity the SI slug was Newtonian1. However, the question has been raised concerning what the effect would be if a non-Newtonian fluid was used instead. We mainly consider the effect of shear thinning although our analysis is generally applicable if the non-Newtonian flow rate/effective viscosity function is known. We address the questions: (i) Does the shear thinning behaviour result in more placement into the higher or lower permeability layer (in addition to the effect of simple viscosification)? (ii) Can the shear thinning effect be used to design improved squeeze treatment?
Application of the SAGD to an Iranian Carbonate Heavy-Oil Reservoir
Authors: Sola B. Sedaee , Rashidi F.
Published: December 2007

Steam injection is the most important thermal enhanced oil recovery; while in this method Steam-Assisted Gravity Drainage (SAGD) is a very promising recovery process to produce heavy oils and bitumen. The method ensures both a stable displacement of steam and economical rates by using gravity as the driving force and a pair of horizontal wells for Injection/production.

SAGD in Sandstone heavy oil Reservoirs has been characterized quite well over the last years. However, there is huge carbonate heavy oil reserves in the world which their production can be enhanced by thermal recovery processes, especially by steam injection.

In this study, Application of SAGD to an Iranian heavy oil carbonate reservoir with low matrix permeability has been investigated. Field-Scale 3-D and simulation models were constructed by using commercial softwares and by thermal simulators to investigate SAGD performance in this reservoir.

The model was further applied to a fractured system and effects of fracture and matrix permeability, Vertical well spacing between producer and Injector and Length of the horizontal section of the injection well on the performance of SAGD process were studied. By comparison with other thermal methods results showed that SAGD can be used as a better EOR method for this heavy oil carbonate reservoir.
Simulating Chemical Placement in Complex Heterogeneous Wells
Authors: Stalker R. , Graham G. M. , Wahid F.
Published: December 2007

Chemical Placement for scale inhibitor squeeze and other near wellbore chemical treatments is recognized as a significant challenge in today's ever more complex operating environments. For heterogeneous wells and long reach horizontal wells, various factors (including heterogeneity, crossflow and pressure gradients between non-communicating zones within the well) all contribute to uneven placement in the reservoir. Current methods to circumvent these problems often rely on extremely expensive coiled tubing operations, staged diversion (temporary shut-off) treatments or overdosing some zones to gain placement in other (e.g. low permeability) zones. For other very near wellbore treatments e.g. acid stimulation, a number of self-diverting strategies have been applied in field treatments with some success. Unfortunately, the properties which make such treatments applicable for acid stimulation may also make them inappropriate for scale squeeze treatments. Other modified lightly viscosified fluids have however been demonstrated to be of significant importance for improving chemical placement thereby reducing the potential for low permeability/high pressure zones being rapidly denuded of chemical during flowback.

Critical to our understanding of such a process is the ability to accurately simulate the effectiveness of such treatments in the laboratory and to use the data to build and validate more effective modelling tools to allow field treatments to be designed. The paper examines the potential benefits of using modified injection fluids, including lightly viscosified and shear thinning fluids to aid uniform scale inhibitor placement in complex wells. Laboratory data using dual linear core flood experiments coupled with mathematical modelling are used to describe cases where such fluids are shown to offer benefit for field application and also those where more minimal benefit would be anticipated, such that the risks associated with the use of modified fluids (e.g. potential formation damage and fines mobilization) would outlay the benefits. The paper therefore describes the effective use and interpretation of detailed laboratory core flood data, mathematical modelling and field evidence to describe the benefits associated with the application of modified lightly viscosified shear thinning fluids in scale inhibitor squeeze treatments.
Using Petrophysical Data to Differentiate A Separate Water Bearing Zone From A Water Level
Authors: Revett L. , Ayeni B. , Farshad F. , Hayatdavoudi A.
Published: December 2007

Hydrocarbons, because of buoyancy, routinely accumulate in the upper portion of originally water-wet sands. Consequently, many petroleum engineers interpret any water bearing zone immediately below as the water level in that sand. However, petrophysical interpretation of the well data may reveal a more rapid water desaturation than is commensurate with the given permeability and pressure conditions of that interval. This condition is indicative of an apparent oil-water contact or pseudo water level rather than the true (free) water level. This can only exist when there is an interruption in the vertical permeability between the oil bearing zone and the water bearing zone.

Higher displacement pressures can be developed above a permeability barrier, which would cause a more rapid water desaturation of the sand than is physically possible for that distance above a true (free) water level. This paper outlines methods of determining whether continuous vertical permeability exists to the water level.
Corrosion Investigation and Prevention of Diesel Tail Gas Underbalanced Drilling
Authors: Wan L. , Meng Y. , Li Y. , Yang L.
Published: December 2007

Diesel tail gas drilling belongs to gas-based underbalanced drilling technology owning the advantages of protecting oil/gas reservoir and improving rate of penetration. Due to complex composition, especially containing carbon dioxide, oxygen, and erodible solid particles, diesel tail gas can give rise severe corrosion to drilling pipes and air compressor valve plates. The corrosion effect of temperature, total pressure and flow velocity on S135 drilling pipe steel and 13 chrome stainless steel were investigated simulating corrosion environment of diesel tail gas. The image and composition of the corrosion product were analyzed by the surface analysis means as scanning electron microscope, X-ray diffraction and so on. The results indicate corrosion rate of dynamic liquid phase exceeds that of dynamic gas phase, S135 steels corroded more badly than 13 chrome stainless steel, at the first the corrosion rate increasing and then decreasing while enhancing temperature, and improving with total pressure or flow velocity rise. Field experience and laboratory test indicate that hereinafter measures should be adopted to protect drilling tools and compressor valve plates from corrosion failure such as improving material quality, modifying tools structure, perfecting environment, also strengthening management and maintenance.

Underbalanced drilling technology on diesel tail gas is used successfully in Well Xing 24. The diesel tail gas drilling is unsuitable for watered gas well and high pressure gas well.

This paper is the first in a series of studies designed to investigate corrosion of diesel tail gas. The goal is to better understand the advantages and disadvantages of diesel tail gas drilling technology, to be able to select the proper corrosion control and extend diesel tail gas underbalanced drilling in suit region.
Our Water Chemistry Contains Organic Acids—So What Does It Mean?
Authors: Durnie W. , Harrop D.
Published: December 2007

The enhancement of brine corrosivity due to the presence of acetate (or anions of other weak acids) in CO2 containing waters has been discussed frequently in recent literature. It has been confirmed that the observed increase in corrosivity is related to the equilibrium concentration of undissociated acetic acid (HAc) in the water and this in turn can be determined via solution speciation calculations – providing the composition of the water is known.

As with all weak acids (and regardless of the in-situ pH), organic acids will be present in both their undissociated form and dissociated form (anions) and since propionic and butyric acids essentially share the same pKa as acetic acid, their molar concentrations can be typically summed under the generic name of the dominant species, i.e., acetate ions (Ac-) and acetic acid (HAc).

This paper discusses the implications of significant levels of organic acids in produced waters (> 1mM) with regards fluid corrosivity. Specifically, how can we account for this in corrosion prediction modelling, as well as ensuring any testing programs conducted correctly reflect the water chemistry and speciation? Our approach to water speciation calculations and subsequent use of this will be discussed in relation to a specific example. The rate of corrosion is not determined solely by solution composition, however, we can’t understand or estimate the corrosion rate without considering the solution speciation.
Alternative Approach to Internal Pipeline Condition Assessment
Authors: Oliver K. E. , John D. G. , Crossland A.
Published: December 2007

Life extension of fields due to enhanced recovery methods and the development of increasingly remote resources has resulted in pipelines being used in very different circumstances to those for which they were designed. There are often large discrepancies between the current operating envelope and the original design conditions. Extension of field life has resulted in pipelines carrying changing fluids compositions beyond the original design life. In order to ensure future integrity of these pipelines, all of these changes in operation need to be assessed/reported and a full understanding of current condition of the pipeline defined. A good appreciation of current conditions, together with future operating conditions and therefore the likely internal corrosive condition of the pipeline can enable forward predictions on pipeline life to be estimated.

This paper give details of an uncertainty based probabilistic approach that enables the internal corrosivity of a pipeline to be assessed under varying operating conditions. This approach enables the risks associated with future maintenance options to be quantified.
Stringent Quality Control and Quality Assurance Process: Key to Successful Fracturing Treatments in Western Siberia
Authors: van Gijtenbeek Klaas , Pavlyuchenko Valentina , Rudnitsky Andrey , Pongratz Reinhard
Published: December 2007

Hydraulic fracturing has probably become the most attractive solution to enhance production in the oil fields of Russia and western Siberia in particular. Besides optimizing the fracturing design with the ultimate goal of increased production, it is equally important that optimized fracturing treatments be pumped successfully in the field. Only a high success rate with a limited number of screenouts can help guarantee that production optimization will be achieved. It is also important to reduce downtime, for operators to have earlier production, and for service providers to optimize equipment utilization.

In western Siberia, harsh conditions exist all year round. The winters are long with temperatures way below freezing for several months in a row. The summers are short, but can be quite warm. Logistics are difficult due to these weather conditions and because roads are rarely in good shape and worksites may be located very far away from equipment bases. To achieve success under these conditions, a lot of emphasis must be placed on quality control (QC) and quality assurance (QA). QC/QA must address many issues on the equipment side due to the harsh environment, but just as important is materials, in particular materials required for preparing the frac fluid and to a smaller extent the proppant used to hold the fractures open.

The frac fluid itself creates the biggest QC/QA challenge. Of special importance is the mixing water because the sources for mixing water vary and the quality of the water changes seasonally. Stringent QC/QA procedures must be in place, including fluid testing under actual reservoir conditions to check the performance of the frac fluid downhole.

This paper describes processes that have been developed and implemented in western Siberia. It includes equipment checks and maintenance as well as QC/QA procedures for frac fluids and their components and proppants. Specific issues related to the special location will be discussed and solutions presented regarding how a successful frac treatment can be provided every time.
Review of MEOR Technology Application in Dagang Oilfield for the Last Decade
Authors: Feng Qing-xian , Ni Fang-tian , Qin Bao-yan , Ma Xian-ping , Ji Chao-feng , Wang Xiao-lin
Published: December 2007

MEOR, particularly indigenous MEOR technology, has been studied extensively in Dagang Oilfield, China, since early 1990s. Based on lab study results, pilot tests were conducted in four different reservoirs (in the Gangxi, Gangdong, Wang-guantun and Kongdian oilfields). In total 24 injection wells and 55 production wells were involved in tests with responses observed in 47 wells.

For MEOR, a series of microbial species, which were suitable to target reservoirs, were developed using produced fluids. The process included separation, culture, and special domestication, contributing to improved oil properties and producing surfactants, emulsion and gas. Core experiments in lab showed that, comparing to waterflooding, microbial flooding could increase the recovery rate by 6-8%. Field tests indicated the cumulative incremental oil production 28,000 tons from the reservoir at 54 to 73°C. One in the tested fields had already been flooded by polymer solution.

Considering the limitation of microbial species variability, match of culture with formation water, numerous of fermentation surface and injections, it was determined to develop indigenous MEOR. This process provided better effectiveness at 60°C. The test results showed improved ecosystem and increased oil production of over 31,000 tons with water cut decreased by 5% at average.

Our study and field tests for microbial flooding showed that reservoir temperature was the most important factor and then microbial nutrients and production pattern follow.
Analysis of Productivity Reduction Due to Non-Darcy Flow and True Skin in Gravel-Packed Wells
Authors: Himmatramka Alok K.
Published: December 2007

Low productivity in oil and gas completions may be attributed to mechanical causes as well as formation damage and/or low formation capacity. Various techniques are available in the industry literature which provide a means of distinguishing pressure losses due to non-darcy flow from pressure losses due to true skin. Jones, Blount, and Glaze1 have presented a procedure using production tests to determine the contribution made by turbulence and all other rate-dependent deviations from darcy flow in reducing a well's productivity. Analyses of transient pressure data measured in conjunction with production tests on a number of gravel-packed gas and oil wells in a field in the Gulf of Mexico support the usefulness of this analytical procedure as a significant means of pinpointing the reasons for low productivity. This enables the engineer to select the appropriate stimulation or remedial workover most likely to improve a well's reduced productivity.
Predicting the Distribution of Thin Bed Reservoir by Broad Frequency Band Seismic
Authors: Li Zishun , Cui Baowen , Guo Xuebin , Wei Xuerui , Mu Jiandong , Qiao Yanguo
Published: December 2007

Aiming at the problem of thin bed recognition in the thin interbed reservoir of the middle-shallow strata in the Songliao Basin, the broad frequency band and ultra high resolution seismic processing technique is studied. After the technique being applied in 3D seismic area of Zhaoyuan in the northern part of Songliao Basin, the seismic resolution increases 2-3 times compared with conventional seismic. It is known that characteristic of AVF is existed in seismic reflection through analyzing broad frequency band and high resolution seismic data and understanding characteristic of amplitude and frequency tuning effect of which originates from thin bed reservoir seismic reflection wave, two methods are given. One is that thickness of thin bed reservoir is calculated by AVF analysis, the other is that the distribution of thin bed reservoir is predicted by using proper broad frequency band and high resolution seismic. Through the fine contrast between seismic and wells data, the top and bottom interface of the F-2 pay zone are made sure. According to the results of seismic interpretation, the technique of seismic attributes extraction along stratum interface and 3D visualization technique are used to predict the horizontal distribution of reservoir on the F-2 pay zone. Taking the prediction result as basis, the applications on optimizing the location of the exploration wells, optimizing the zone of production test and analyzing the continuity of pay zone between the production wells are studied. They demonstrate the advantage of the high resolution seismic in the thin interbed reservoir prediction and the seismic recognition of lithologic reservoir.
Determination of the Zone of Maximum Probability of Asphaltenes Precipitation Utilising Experimental Data in an Iranian Carbonate Reservoir
Authors: Hamid K.
Published: December 2007

Asphaltenes precipitation is one of the major operational problems affecting oil production in the Bangestan reservoir in south of Iranian fields. Precipitation of asphaltenes in reservoirs, wells and production facilities can have severe detrimental impact on the economics of oil production because of a reduction of well productivity and/ or clogging of production facilities. A field methodology based in the influence of pressure in asphaltenes precipitation has been designed and implemented to estimate the zone of maximum probability of asphaltenes precipitation. Nodal analysis is applied to determine pressure versus depth behavior at the well for different operational conditions. Knowing the saturation pressure and the flocculation onset pressure, the methodology allows the determination of the most probable range of depth at which asphaltenes precipitation will occur. The purpose of this methodology is determine the optimum operational conditions that maximize production at minimum risk of asphaltenes precipitation, as well as to select the better preventive measure for each particular case, thus maintaining overall control of the asphaltenes plugging problem. In this paper, field applications of the methodology are shown. Depending on the depth range of asphaltenes precipitation occurrence, reperforation of the producing interval, hydraulic fracture is recommended.
Studies on Less Expansive Environmentally Safe Polymers for Development of Water-Based Drilling Fluids
Authors: Sharma V. P. , Mahto V.
Published: December 2007

Recently there has been lot of interest and research activity started in the development of new products and combinations for the development of ecofriendly drilling fluids using chemicals, which are less toxic and biodegradable materials. In this work, an attempt has been made to develop water based drilling fluids using Indian bentonite clays and new ecofriendly polymers, which has been found to be cheaper than the conventional polymers used in oil well industry. The tamarind gum and tragacanth gum, which are not used in water based drilling fluids, had been found suitable. This has been confirmed by doing experiments using standard procedure adopted by oil industry. The temperature stability of drilling fluid additives was studied using Hot Air Rolling Oven and Aging Cells. The formation damage was carried out using oil field core samples on Ruska liquid permeameter. The laboratory investigation furnishes that combinations of these polymers and bentonite have favorable rheogical properties with less formation damage.
Fighting Against Non-Unique Solution Problems in Heterogeneous Reservoirs Through Numerical Well Testing
Authors: Shi-Yi Zheng
Published: December 2007

Numerical well testing started in about a decade ago. The technique was developed to tackle well testing problems in heterogeneous reservoirs. Integration of geoscience and well testing for improved fluvial reservoir characterisation was the first project of this kind supported by the oil industry that time. When approaching non-unique solution problems in heterogeneous reservoirs, the traditional analytical approach based on the ideal reservoir conditions failed. An option to get an approximate solution for the problem is to solve the non-linear pressure diffusivity equation through well test numerical modelling and simulation. Well test analysis and interpretation conducted on this basis is called numerical well testing. This technique has been proved, through study and research in the past few years, to be an effective way to solve the problems not only for single phase flow in heterogeneous formation, but also for multi-phase (heterogeneous fluid properties) flow in heterogeneous formation.

This paper will present study result and new development in numerical well testing in recent years. These are based on research and studies from a number of M.Sc. and M.Phil. projects at Heriot-Watt University. Due to the continuous support from the oil industry since the fluvial reservoir characterisation project, numerical well testing has been extensively conducted in the Institute of Petroleum Engineering at Heriot-Watt University. This technique has been used to tackle well testing practical problems as well as for academic research. There will be five aspects to be covered in this paper. These are: Numerical well testing forward modellingNumerical well testing for reservoir model calibrationNumerical well testing for future production forecast (well test design)Numerical well testing for reservoir monitoringNumerical well testing in heterogeneous reservoir saturated with heterogeneous fluids (multi-phase, e.g. gas-condensate reservoirs)

Case studies and filed examples selected for this paper will be used to demonstrate procedures; methods developed and illustrate field applications.
An Extension Of The Pollard Analysis Method Of Well Pressure Build-Up And Drawdown Tests
Authors: Pirson Richard S. , Pirson Sylvain J.
Published: December 2007

The Pollard method for analyzing well pressure drawdown and build-up tests presented in 1958 permits the calculation of the well skin effect and of the volume of the coarse pore volume system affected by the well. It was devised primarily to design and predict results of acid treatments. The present study extends the Pollard analysis to the calculation of the fine pore volume system (often called "matrix" porosity) and to the calculation of the "radius of influence" of a well before and after well stimulation treatment. The method permits to ascertain if a sufficient number of wells are drilled in order to drain effectively a given field or lease. The extension of the Pollard method is based on laboratory tests made with electric analogs of the various simulated porous systems. Limitations and field examples from fractured and vuggy reservoirs are given.

In many reservoir engineering calculations it is important to know the pressure variations since many of the variables in reservoir engineering are dependent on pressure. It is well known that reservoir pressure in a producing or in a shut-in well varies with time, but it is not so well known how exactly the reservoir pressure varies mathematically with time. In fact, as will be discussed later, several papers have been written outlining various methods of analyses of pressure build-up curves.
Benefits of Linear Bivariate Log Analysis Models
Authors: Collins H. Neal , Pilles D.
Published: December 2007

As computerized log analysis becomes more sophisticated it becomes more difficult for the log analyst to assess the validity of the models being used. This paper suggests that current efforts to define and display uncertainty criteria should be increased. Two samples are presented to show how functional analysis, applied to linear bivariate models, can provide cap-sulized information useful to the analyst in monitoring input data and testing model validity.
Trends of the PVT-Properties of the Gas-Oil Reservoir Fluids and the Thermodynamic Effects Occurring at the Separation of the Produced HC Mixtures
Authors: Brusilovsky A. I. , Kaplan A. L. , Nugayeva A. N.
Published: December 2007

The paper offers methodological approaches and describes the results of integrated use of data of production, laboratory and theoretical studies of the properties of the natural HC mixtures produced in the West Siberian oil and oil-and-gas fields.

It shows that in order to increase dramatically the oil production, the optimal pressure should be defined for the first-stage separation at the booster pipeline pumping station when producing light oil with high solution gas-oil ratio.
One-Trip Sand-Control / Liner Hanger / Big-Bore Completion System
Authors: Hoffman C. R.
Published: December 2007

This paper introduces a revolutionary completion system which, by design, replaces conventional TCP perforating and gravel packing through a technique using hydraulic pressure only. This technology also eliminates formation damage caused by perforating and reduces skin values. It is a new-generation, screenless sand-control completion system.

During the development of this technology, several versions were tested, leading to the system offered today. A telescoping conduit containing sand-control media comprising stainless steel beads was chosen for its durability, erosion resistance and plugging resistance. The system contains no explosives whatsoever; therefore many issues pertaining to this were eliminated.

A JIP (Joint Investment Project) team consisting of three major operators, a service company and an independent tool manufacturer was formed with several criteria to meet. The team was posed with the task of developing a system whereby formation damage was eliminated and skin values were greatly reduced. Conventional perforating is the major cause of formation damage, so the primary goal was to eliminate this and still be able to achieve connectivity with virgin reservoirs and maintain full bore production and/or injection rates.

Also, one-trip capability and user-friendliness was of primary concern as with all new technologies; if this system were to cost operators more throughout the completion of any given well, it would have no merit in the marketplace. Therefore the system was designed around conventional liner and cementing techniques, as these are of vital importance in the success of a quality completion.
Development of Moomba North Gas Field: Lessons Learned from Integrated Study Followed by an Infill Drilling Campaign
Authors: Herweijer J. C. , Barley M. , Bainbrigge P. , Herries T.
Published: December 2007

Field development planning based on integrated studies, including construction of a 3D geo-model, is an accepted standard for development of larger assets. The need to keep field development plans ‘evergreen’ is well recognized, but often difficult to realize in practice.

This paper will focus on the results of a drilling campaign that followed an integrated study previously described in SPE paper 62901(Herweijer et al., 2000). As with many drilling campaigns, the results covered a range from very positive to negative outcomes. This paper will show how the result of the campaign, which was an overall success, was affected by:

– The modeling process, which assumed a base case with perturbations. It became anchored on a specific, optimistic, fluid contact scenario, rather than including a realistically wide range. – The process of multi-disciplinary work, which, although rigorous, did not in itself guarantee that a realistic range of scenarios had been covered. – Changes in team membership prior to execution of the infill campaign. This lead to a partial lack of ownership, resulting in the missing of signposts that could have lead to re-tuning the campaign by accounting for more downside scenarios. – The relatively elaborate study and modeling process, which discouraged updating and hence lead to poor integration of some early negative drilling results into the model.

The conclusion of the paper is that the whole study became somewhat ‘model-centric’. The model served as an unbeatable ‘truth’: trusted more than pre-model mapping, not fully connected to post-model ‘mass production’ infill drilling results, and used on problems to which it was not suited.

As a result of the lessons learned we have been able to assess the real value of knowledge continuity and model ‘ever-greening’ from early stages of development through to later ‘harvest’ drilling.