bluuebunny/crossref_metadata_2025 huggingface dataset:
Advantages of Permanent Integrity Monitoring using Guided Wave Tomography
Authors: Bloom J. G. , Heerens G. J. , Volker A. W.
Published: July 2010

Corrosion and erosion are two major degradation mechanisms of piping systems and pipelines that both lead to wall thickness loss. To ensure sufficient integrity levels of these assets NDE is currently conducted at time based intervals often associated with shut downs. However, both economical and social requirements are pushing the industry to higher levels of availability, reliability and safety of installations at minimum costs. Using permanent sensors that continuously monitor the wall thickness of assets over large areas allows improvement of the availability of installations at lower inspection costs. Because when inline data is continuously available the maintenance can be planned (just) in time at the most optimal moment. Therefore, the permanent sensors will save inspection costs and minimize unplanned maintenance. This can not be achieved with the current method of periodic inspections and local measurements even when this is done risk based, because some corrosion processes behave unpredictable. This paper demonstrates a system that monitors the wall thickness of pipe lines over large areas in an economical attractive way using a limited number of low-power ultrasonic transducers. By applying tomographic inversion to the travel time of guided wave modes along different paths, a wall thickness map with 100% coverage can be obtained. Experimental results on a 10" steel pipe with a wall thickness of 8 mm show that this system is able to detect and size defects with a depth of 10% and diameter of 15 cm. The area covered in this case was the complete wall of a pipe with a length of 4 m. This paper further explains the performance and it will give an outlook of the possible applications and possibilities to integrate other functionality like crack monitoring with the same system.

In this paper there will be a focus on applying this concept in new build installations because of the low additional costs involved when applying the sensors while manufacturing the assets. This makes it very attractive for remote oil and gas production installations. However, it has been shown that it can save costs also for existing installations by replacing inspections at sections of installation, which are not piggable and difficult to approach. This is in general the case in oil and gas (offshore) production installations. Cost of inspection projects are extremely high in off shore environments and saving one inspection job can probably guarantee already your return on investment. Next, when using this technique it will also allow to make a wall thickness map of areas that are not accessible by current inspection techniques like corrosion under supports and feed through.
Evaluation of Alternative Horizontal Well Designs for Gas Production from Hydrate Deposits in the Shenhu Area, South China Sea
Authors: Zhang Keni , Moridis George J. , Wu Nengyou , Li Xiaosen , Reagan Matthew T.
Published: July 2010

Gas hydrate deposits were confirmed in the Shenhu Area, the north slope of South China Sea during a drilling expedition in 2007. Hydrate deposits in the area are distributed in disseminated forms in forams-rich clay sediments with permeable overburden and underburden layers. Production of gas from such a type of hydrate deposits is very challenging. In this study, we develop a numerical approach for investigation of gas production strategies by horizontal wells and preliminary estimation of the production potential based on the limited data that are currently available. Numerical models are built to represent the typical hydrate deposits in the area, including the thickness of the Hydrate-Bearing Layer (HBL), hydrate saturation, water depth, temperature at the sea floor, initial thermal gradient and pressure distribution. The models are used to simulate the different production schemes and well designs. In this paper, production strategies of horizontal well system with combination of depressurization and thermal stimulation are investigated through numerical models. Gas production potential from the deposits and effectiveness of the different production methods are evaluated. The simulation results indicate that with current technology, gas production from Shenhu hydrate deposits may not be economically efficient for all the production strategies we have investigated.
Use of Elemental Capture Spectroscopy to Accurately Determine Reservoir Lithology and Porosity in High Pressure and High H2S Environment
Authors: Zhao ZuoAn , Tang XuePing , Yu DaiGuo , Murray Doug , Zhao HaiPeng
Published: July 2010

The lithology of a producing gas reservoir in an area of the Sichuan basin in southwest China is a complex carbonate. Core analysis has revealed a strong correlation between dolomitization and reservoir quality, the process of dolomitization increases reservoir porosity and permeability, and hence overall reservoir rock quality. As such dolomite content is a key parameter in the classification of reservoir rock quality.

Historically, in carbonate reservoirs the estimation of dolomite content from wellbore geophysical data has been via neutron-density cross-plots. The technique was successful when reservoir lithology was relatively simple, such as a combination of limestone and dolomite, and the reservoir fluid was either oil or water. The presence of gas can shift both the neutron porosity and formation density measurements such that a dolomite lithology could be misinterpreted as limestone. However, the photo-electric absorption measurement acquired with modern formation density logs is strongly dependent on lithology and only minimally affected by reservoir fluid. Hence from the combination of neutron porosity, formation density and photo-electric absorption one can resolve simple carbonate lithology even in the presence of gas.

The aforementioned gas reservoir in the Sichuan basin has both high reservoir pressures and high concentrations of H2S, hence to maintain a safe drilling environment the drilling fluid is weighted with barite. The addition of barite makes photo-electric absorption measurements meaningless for petrophysical evaluation.

This paper describes a new technique to accurately describe complex reservoir lithology from elemental capture spectroscopy. The technique is independent of photo-electric absorption and includes elemental measurements of magnesium, calcite, quartz and sulfur. Additionally formation matrix density is derived from the measured elements, which dramatically improves the evaluation of formation porosity. A field example is shown where excellent agreement with core is achieved.
Reserves Estimations under New SEC 2009 Rules when using Probabilistic Methods
Authors: Wheaton R. , Coll C.
Published: July 2010

The new SEC rules (Jan 2009) allow the use of probabilistic methods for reserves estimations. The main advantage of probabilistic modelling methods is that they provide an understanding of the confidence levels associated with each reserves/resources category. Reserves evaluators need to ensure regulatory compliance of the output of these probabilistic methods with the reserves definitions adopted by the SEC or other regulatory bodies. A Cumulative Distribution Function of hydrocarbon recovery is obtained as part of a probabilistic modelling workflow, from which estimates of P90, P50 and P10 result. However, these estimates are not necessarily SEC compliant. We may therefore require an additional analysis of the parameters that have been used for each model. The aim of the paper is to provide technical guidance on methodologies for obtaining P90, P50, P10 reserves and on obtaining compliant reserves estimates when these are available. This approach should help to standardize industry external reserves reporting.

To understand and quantify the impact of major uncertainties in a reservoir there are different methodologies used in industry with the objective of achieving a fully integrated probabilistic reserves analysis. An examination of different methodologies depending on the stage of appraisal and development of a field is presented. The output of this analysis will be a cumulative distribution of hydrocarbons from which P90, P50, mean and P10 reserves are selected.

In summary the aim of this paper is to provide technical guidance on how to estimate reserves for external complaint reporting if probabilistic methods are used.
Application of Ferrofluid for Enhanced Surfactant Flooding in EOR
Authors: Kothari Nikita , Raina Bhavna , Chandak Krishna , Iyer Venkat , Mahajan Hrishikesh
Published: July 2010

Improved Oil Recovery (IOR), techniques offer prospects that enhance the displacement of oil from the reservoir, ultimately producing 30 to 60 percent, or more, of the reservoir's original oil in place. The most important criteria in IOR- Surfactant Flooding is to determine if the interfacial tension (IFT) can be reduced enough to produce incremental oil.

One of the key recovery problems in oil-wet reservoir is overcoming the surface tension forces that tend to bind the oil to the rock. In water wet reservoirs, surface tension forces act to create bubbles of oil, which can block pore passages as the bubble resists movement in the increased surface area associated with squeezing through the passages. These surface tension forces are the primary reason why reservoirs become increasingly impermeable to oil, relative to water, as the water saturation increases.

Ferrofluids are a special category of smart nano-materials, in particular magnetically controllable nanofluids. The ferromagnetic nano-particles are coated with a surfactant to prevent their agglomeration. As a result of their composition, Ferrofluids possess a unique combination of fluidity and the capability to interact with a magnetic field. The addition of a surfactant will greatly reduce the Interfacial Tension and in water-wet reservoirs, where oil globules are formed, ferrofluid shatters it. Also, as ferrofluid comes in contact with the reservoir fluid, it interacts with the crude in the reservoir & due to the presence of dipole moment, the reservoir fluid molecules align, thus reducing the resistance to the flow.

To sum up, reduction in Interfacial tension, thus reducing resistance to the flow, can be easily achieved by making use of Ferrofluid-enhanced surfactant. Oil can be made even more polar using Ferrofluid which will act as a better solvent for the surfactant.
Pre-selection of Reservoir Models From a Geostatistics-Based Petrophysical Seismic Inversion
Authors: Ravalec-Dupin M. Le , Enchery G. , Baroni A. , Veiga S. Da
Published: July 2010

A new geostatistics-based seismic inversion method is introduced in this paper for determining reservoir models consistent with base seismic information. The proposed methodology entails two steps, the second one only being examined in this paper. First, cubes of acoustic velocities or impedances are derived from seismic inversion. Second, these data are incorporated into a matching process to identify reservoir models leading to acoustic responses close to the reference acoustic data. The parameterization of the facies and petrophysical properties populating the reservoir models is based upon the gradual deformation method (GDM), which relies on geostatistical concepts. This particular feature makes it possible to change the spatial distribution of the property of interest from a few parameters while preserving its spatial variability. The matching process is driven from a global optimization algorithm known as the particle swarm optimization (PSO). Such a global approach is reasonable for the problem considered as the forward modeling is very fast. A variant of the PSO algorithm is implemented to take advantage of the gradual deformation method properties. This approach yields reservoir models which honor the seismic data better than those derived from stochastic simulation only with seismic used as a secondary variable. A numerical experiment is then presented to stress the applicability of the proposed matching methodology: the GDM-based PSO approach is used to identify facies reservoir models and water-oil contact consistent with some reference acoustic P-wave impedances.
Research on Development Rules and Strategies in the Low R/P Ratio of Tarim Major Sandstone Reservoirs
Authors: Yu Lijun , Feng Jilei , Zhang Shuguang , Lian Zhanggui , Chang Yuwen , Feng Jinde , Yan Jianwen
Published: July 2010

Based on the major Tarim sandstone oil reservoirs, with seven typical reservoirs as the fundamental study units, some relevant researches are conducted, which include changing patterns and their major contributing factors analysis of production decline rate, water content increase rate, ratio of reserve to production (R/P ratio) and balance index of reserve to production. The production decline rate change rules and its major contributing factors have been specifically analyzed quantitatively. It is believed that, comparing with domestic and foreign land reservoirs, the major sandstone reservoirs have made satisfactory progress. After a period of high-yield and stabilized production, the reservoir development has entered a comprehensive adjustment and low yield stage. In the decline stage, the production decline rate is high and the R/P ratio is in a low level.

Through the studying of R/P ratio and balance index of reserve to production of different kinds of reservoirs, rational boundary of R/P ratio has been defined, reasonable development system's establishment and technical development policy for 8-to-10-year stable production have been proposed.

The research indicates that, multilayer developments, multi-adjustments and pressure maintenance development are all necessary to keep the oil production stable. Through well pattern thickening, injection-structure adjusting and hydro-dynamic method, water-flood recovery can be increased by 8.7%. Thus the major sandstone reservoirs can keep stable production by 2015. However in the long run, the potential of increasing recoverable reserves by water drive is limited. For technological breakthrough in reserve replacement, the author suggests speed up the research and experiment of gas injection method to enhance recovery. These research results have already been applied in the annual plan as well as in the oil field plan for the next five years.
Drilling Optimization Based on the ROP Model in One of the Iranian Oil Fields
Authors: Mostofi M. , Shabazi K. , Rahimzadeh H. , Rastegar M.
Published: July 2010

In today's drilling industry, all considerations are involved to reduce drilling operation expenditure. In several cases, the drilling optimization is the key point to make a drilling operation economically satisfied. Appropriate bit selection and optimum operating condition can lower the drilling expenditure, effectively. Drilling models are drilling simulators, which can evaluate the effect of different operating conditions on the drilling rate of penetration and drilling expenditure, quantitatively.

The model constants are required to start the optimization process. The model constants are bit constants and formation rock strength. They can be determined from either laboratory tests or the drilling information of offset wells. When model constants are calculated from field data, it is beneficial to use pattern recognition and statistical tools to eliminate the noises and out of range data.

When the drilling model is developed, the optimum operating condition for each bit is calculated. Then, subsequent cost analysis is carried out to determine the cost per foot value of bits in their optimum drilling condition. Consequently, bit runs are compared based on their cost per foot values. Moreover, bit run with minimum cost per foot value along with its optimum drilling condition is selected for drilling of formation under investigation.
From Oil-Prone Source Rock to Gas-Producing Shale Reservoir – Geologic and Petrophysical Characterization of Unconventional Shale-Gas Reservoirs
Authors: Passey Q. R. , Bohacs K. M. , Esch W. L. , Klimentidis R. , Sinha S.
Published: July 2010

Many currently producing shale-gas reservoirs are overmature oil-prone source rocks. Through burial and heating these reservoirs evolve from organic-matter-rich mud deposited in marine, lacustrine, or swamp environments. Key characterization parameters are: total organic carbon (TOC), maturity level (vitrinite reflectance), mineralogy, thickness, and organic matter type. Hydrogen-to-carbon (HI) and oxygen-to-carbon (OI) ratios are used to classify organic matter that ranges from oil-prone algal and herbaceous to gas-prone woody/coaly material.

Although organic-matter-rich intervals can be hundreds of meters thick, vertical variability in TOC is high (<1–3 meters) and is controlled by stratigraphic and biotic factors. In general, the fundamental geologic building block of shale-gas reservoirs is the parasequence, and commonly 10's to 100's of parasequences comprise the organic-rich formation whose lateral continuity can be estimated using techniques and models developed for source rocks.

Typical analysis techniques for shale-gas reservoir rocks include: TOC, X-ray diffraction, adsorbed/canister gas, vitrinite reflectance, detailed core and thin-section descriptions, porosity, permeability, fluid saturation, and optical and electron microscopy. These sample-based results are combined with full well-log suites, including high resolution density and resistivity logs and borehole images, to fully characterize these formations. Porosity, fluid saturation, and permeability derived from core can be tied to log response; however, several studies have shown that the results obtained from different core analysis laboratories can vary significantly, reflecting differences in analytical technique, differences in definitions of fundamental rock and fluid properties, or the millimeter-scale variability common in mudstones that make it problematic to select multiple samples with identical attributes.

Porosity determination in shale-gas mudstones is complicated by very small pore sizes and, thus, large surface area (and associated surface water); moreover, smectitic clays that are commonly present in mud have interlayer water, but this clay family tends to be minimized in high maturity formations due to illitization. Finally, SEM images of ion-beam-milled samples reveal a separate nano-porosity system contained within the organic matter, possibly comprising >50% of the total porosity, and these pores may be hydrocarbon wet, at least during most of the thermal maturation process. A full understanding of the relation of porosity and gas content will result in development of optimized processes for hydrocarbon recovery in shale-gas reservoirs.
New Directional Drilling With Liner Systems Allows Logging and Directional Control While Getting Casing Across Trouble Zones
Authors: Srinivasan A. , Frisby R. , Talbot T. , Paraschiv M.
Published: July 2010

In deepwater and other challenging environments, operators often have to drill through ‘problem zones.’ These zones could be rubble zones, tar zones, or just unstable pressure zones. In the past, operators often had to drill through these areas, lose drillstrings, and drill a sidetrack, hoping that they might be able to avoid these areas the second time. But with the advancement of steerable drilling liner systems, we now have a solution in place to tackle the toughest drilling challenges. With much of the equipment coming from field-proven technologies, the next generation of steerable liner systems is increasingly proving to be the answer to reducing nonproductive time. This technology will allow operators to drill well sections directionally with the liner string as part of their normal drilling operations and case off that section all in one trip. This paper highlights these steerable liner systems and illustrates their ability to outperform conventional casing while drilling systems.
A Study on Deliverability Ratio Relationship between Horizontal Well and Vertical Well
Authors: Luo Yinfu , Zhu Guojin , Sun Fujie
Published: July 2010

The empirical range of deliverability ratio between horizontal well and vertical well is usually regarded as 2–5. But actually, this range is too large and the real ratio may not be within it. To quantify the deliverability ratio relationship between horizontal well and vertical well more accurate, the deliverability ratio relationship is derived based on modified Joshi's horizontal well deliverability formula and vertical well deliverability formula. Then as for different horizontal well lengths with known parameters of the pay zone in the vertical well where the horizontal well locates, corresponding deliverability ratios can be obtained. And then the horizontal well deliverability can be predicted by multiplying the known appraisal well (vertical well) deliverability and the deliverability ratio.

Sensitivity analysis between the deliverability ratio and relevant parameters is done by using pay zone, fluid and well parameters of Q oilfield of China Bohai Bay. The results show that as for different parameter combinations, the deliverability ratio can be within or without the range of 2–5; skin factor and off-center distance have little effect on the deliverability ratio, while as horizontal length increases, permeability anisotropy factor increases and pay thickness increases as well as drainage radius decreases, the deliverability ratio will decrease obviously. These regularities coincide with actual development regularity, which verifies the accuracy of the proposed method.

The proposed method quantifies the deliverability ratio range between horizontal well and vertical well, and increases prediction accuracy of horizontal well deliverability; therefore it is of great practicability, especially for early stage reservoir development.
Optimisation of Uncertain Structural Parameters Using Production and Observation Well Data
Authors: Irving A. , Robert E.
Published: July 2010

Conditioning of fault properties to production data is usually achieved by ad hoc modifications without consideration of prior probability distributions or physical realism. Here, we compare two geologically-based workflows for conditioning fault uncertainties to production data: a sensitivity analysis and optimisation scheme based on factorial experimental design and an alternative approach using the Ensemble Kalman Filter (EnKF). These methods have been tested on a producing reservoir whose combination of structure, well pattern and production history make it particularly suitable. The misfit between simulated and observed pressures was most influenced by reservoir volume (horizon depth, gas-water contact and fault positions) and inter-panel connection (fault juxtaposition and transmissibility). Using a response surface method, the best match to the observed data was obtained with a small connected volume and transmissible central fault. Application of the EnKF to fault displacement, permeability and thickness gave a similar match to the observed data; this was not improved by the inclusion of well oil production rate in the objective function. While comparable, the two optimisation methods each have different advantages and disadvantages. The method applied should be chosen in light of the particular field case and uncertainties being studied.
Mature Oil and Gas Fields: T*H*IN*K Process to Achieve Mature Field Production Excellence
Authors: Ondracek Walter , Liebl Werner
Published: July 2010

It is technically and financially a challenging task to produce mature assets economically, and mature oilfield operators like OMV have to stretch themselves to the limits to succeed: an average performance in delivering production rates, recoveries and CAPEX / OPEX spending will not be good enough - we have to arrive at ‘Production Excellence’.

In the past mature field operations have been built upon strong functional structures. Our approach and success was based on a hierarchical organisation and experienced people to run the field operations.

As OMV E&P started to introduce business processes in the late 90ies, our processes supported the old system: thinking remained functional.

Today, however, we look for ‘Production Excellence’, which does not only mean first class performance in operations but also effective control of cost and production, continuous identification and realization of opportunities to increase the value of our assets and finally the improvement of the Key Performance Indicators (KPIs) of our activities.

To achieve this, we developed a new Produce Process Management System which stretches across organisational boundaries and assures that everyone in the organisation sees the full picture. We closely cooperated with operational key personnel to define a new process, which provides the link to organisation, supports collaboration and integration of disciplines visualizes and controls information flow, and measures time and cost of process activities.
The Green Approach in Downhole Workover Operations
Authors: Liu He , Ye Peng , Chen Xianjin
Published: July 2010

This paper displays a new approach in downhole workover operations. Environmental pollution was resulted from downhole workover operations, such as spills of crude oil and produced water. These accidents can pose safety risks to operations, and has direct adverse impact on local people daily lives, public health, and agriculture etc. Workover operations are strictly regulated by HSE Management Standards.

After many years of practices, a series of multi-purpose clean downhole workover technologies have been developed and many types of equipment have been created, such as movable produced water treatment technology, to prevent spills of oil and produced water. These technologies and equipments have guaranteed green downhole workover in Daqing Oilfield.
Evaluation of the Petrophysical Properties of a Carbonate-rich Caprock for CO2 Geological Storage Purposes
Authors: Tonnet Nicolas , Broseta Daniel , Mouronval Gérard
Published: July 2010

Prior to any CO2 geological storage operation, the caprock's ability to prevent CO2 leakage must be carefully assessed. This ability is primarily related to the caprock's pore structure and to the interfacial properties of the caprock and the fluids in place, namely the brine that imbibes the caprock and the CO2 stored in the underlying reservoir. This paper reports an experimental effort to characterize some of these parameters, using as a working example the carbonate-rich caprock and reservoir conditions of the Rousse depleted gas field in the South-West of France, where an estimated 120000 tons of CO2 will be injected during two years. The parameters examined are: (i) the caprock wetting behavior in the presence of CO2, (ii) the caprock intrinsic (single-phase) permeability, (iii) the CO2 breakthrough (or displacement) overpressure, i.e., the minimum pressure difference between CO2 and brine required for CO2 to penetrate and flow through the brine-saturated caprock, and (iv) the caprock effective permeability to CO2 after breakthrough. The latter two parameters are indicative of, respectively, the caprock's capillary sealing efficiency and CO2 leakage rate once breakthrough has occurred.

The main observations and results are as follows. (i) The water-wet character of the Rousse caprock in the presence of CO2 in storage conditions is confirmed through a series of contact angle measurements on substrates. (ii) Single-phase (brine) permeability coefficients measured in steady-state conditions are extremely small and strongly sensitive to the effective stress, i.e., to the difference between the confining pressure and the pore fluid pressure. They do not exceed 20-25 nanodarcy (10-21 m2) for effective stresses below 4 MPa, and 1 nanodarcy for effective stresses in the range of 10 MPa and above. (iii) Gas breakthrough in two different brine-saturated caprock samples, using either CO2 or N2 as the displacing gas phase, occurs in one sample for a CO2 overpressure in excess of 7.6 MPa, and in the other sample for a N2 overpressure in the interval of 4.5-6 MPa. In the latter sample, the effective permeability to N2 after breakthrough is extremely low, below 1 nanodarcy; some "aging" effects are observed upon subsequent resaturations with brine and CO2 breakthrough experiments, with a CO2 breakthrough overpressure lower than expected and an increasing effective permeability to gas, yet still lower than 2 nanodarcy after two consecutive brine resaturations and CO2 breakthroughs.
Seismic History Matching of Nelson using Time-lapse Seismic Data: An Investigation of 4D Signature Normalization
Authors: Kazemi Alireza , Stephen Karl D , Shams Asghar
Published: July 2010

History matching of a reservoir model is always a difficult task. In some fields we can use time-lapse (4D) seismic data to detect production induced changes as a complement to more conventional production data. In seismic history matching we predict these data and compare to observations. Observed time-lapse data often consists of relative measures of change which requires normalization. We investigate different normalization approaches, based on predicted 4D data, and assess their impact on history matching.

We apply the approach to the Nelson field in which four surveys are available over nine years of production. We normalize the 4D signature in a number of ways. Firstly we use predictions of 4D signature from vertical wells that match production and derive a normalization function. As an alternative, we use cross-plots of the full field prediction against observation. Normalized observations are used in an automatic history matching process where the model is updated. We analyse the results of the two normalization approaches and compare against the case of just using production data.

The result shows that when we use 4D data normalized to wells, we obtain 49% reduced misfit along with 36% improvement in predictions. Also over the whole reservoir, 8% and 7% reduction of misfits for 4D seismic are obtained in history and prediction periods respectively. When we use only production data the production history match is improved to a similar degree (45%) but in predictions, the improvement is only 25% and the 4D seismic misfit is ten percent worse.

Finding the unswept areas in the reservoir is always a challenge in reservoir management. By using 4D data in history matching we can better predict reservoir behaviour and identify regions of remaining oil.
An Integrated Approach on Carbonate Reservoir Evaluation by Combining Borehole Image and NMR Logs - A Case Study in Ordovician Carbonate, East China
Authors: HuiJun Hou , HuaYun Yun , Yun Xie
Published: July 2010

This paper is a case study in an Ordovician carbonate, east China. Most carbonates are buried hill of Ordovician age and the reservoirs are dolomitized. Fractures are very important here as the porosity is often very low (about 2–5%). But the puzzle is the higher fractured zones not always are the higher production zones. So the two important things that one should be concerned with are (i) how to find the fractured zones, and (ii) the factors influenced the production rates.

An integrated approach using a combination of borehole image and NMR logs is applied in this study. Borehole images are used to extract fractures, vugs, rock textures and pore textures. Structure profile across the wellbore is created from the image dips as well, as an aid of the fracture analysis. NMR Bin data and T2 distribution spectrum are displayed to reflect pore textures, and a relative permeability also calculated from NMR logs. Furthermore, the morphic rock types are classified in details base on borehole images and lithology identified with other openhole logs. Nine morphic rock types are identified. All the summary data are displayed in one integrated plot for thorough analysis. The reservoir properties are found well related to morphic rock types and pay zones are observed located near the fault zone. Faults in one hand enhance the reservoir by dissolution on fracture and vugs near the fault zone, while in the other hand, it impair permeability of the fractures with clays in the fault zone. Those clay filled conductive fractures can be seen in borehole image, but no any permeable indictors in NMR data. The vuggy fractured dolomite is deemed as pay zone. The results are validated by the later well production. The combination of borehole image and NMR logs provide a valuable solution for clear understanding of this reservoir.
Outlook of Drilling/Production Equipment Managment and Rebuilding Techniques in Daqing Oilfield
Authors: Gang Cao , He Liu , Guochen Shi , Mingyan Lu , Mingzhen Liu , Honghai Wang , Yunlong Zhao , Bo Yu
Published: July 2010

Daqing Oilfield is the largest continental oilfield in China. After 50 years development, the total quantity of drilling and artificial equipments of the oilfield has reached to a considerably large size and it is still increasing with a higher rate. Daqing Oilfield had to spend a lot in maintenance and renewal of the equipments. For example, only the replacement of artificial lifting equipments would cost 156.75 million USD each year. In the past tens years, Daqing Oilfield invested huge funding to improve the equipment management and recycling manufacturing techniques. After years of study, a set of management methodology was created and a series of rebuilding techniques were developed. This paper presented the practices both in drilling and production equipment management and rebuilding techniques. This paper also decribe the outlook of oilfield equipment management and rebuilding techniques in the future.
Production-induced Stress Change In and Above a Reservoir Pierced by Two Salt Domes: A Geomechanical Model and Its Applications
Authors: Schutjens P. M. , Snippe J. R. , Mahani H. , Turner J. , Ita J. , Mossop A. P.
Published: July 2010

Production decreases the pore fluid pressure and increases the effective stress acting on the load-bearing grain-framework that makes up the reservoir. As a result, the reservoir deforms and compacts, and because it is connected to the rocks around it, there will be deformations and displacements in these rocks too. Well known effects are surface subsidence, wells damaged by shear, and timeshifts in 4D-seismic. Less well known is how the changes in the stress field itself should be taken into account in operations, e.g. to design infill wells and to plan production stimulation by hydraulic fracturing or waterflooding of the reservoir.

We present a geomechanical model for the initial stress field and production-induced stress changes in and around a steeply-dipping hydrocarbon reservoir penetrated by two large salt-domes. The model integrates 3D seismic and geological understanding, geomechanical data from wells and analogues, and depletion patterns from fluid-flow (dynamic) simulation. Our model results confirm published models of principal stress orientation in rocks pierced by salt domes. The depleted-model results show stress changes up to several MPa in magnitude compared to the pre-production stress state, but only limited changes in the stress orientations. The model highlights the influence of structural dip and time-dependent salt-sediment interaction on stress changes.

We then describe the application of the model in wellbore stress analysis for infill wells and in a water-injection scheme that has (we think) been severely impacted by injection-induced fractures propagating into the reservoir towards the producer wells. We explain how the latter application uses a 3D flow simulation model coupled to a dynamic fracture propagation model. The geomechanical model provides key input: stress magnitude and orientation. Results are validated against more conventional analysis of real-time pressure data.

In both applications, the integration of geomechanics in 3D static and dynamic models improved insight in the rock response to drilling and waterflooding, thus helping to optimise production.
Parametric Design and Application of Jet Pumping in an Ultra-Deep Heavy Oil Reservoir
Authors: Chen Shengnan , Yang Daoyong , Zhang Qi , He Jun
Published: July 2010

It is extremely difficult to produce heavy oil from an ultra-deep reservoir due to the long lifting path and the high flowing resistance in the wellbore. During its path to the surface along the production string, the reservoir fluid becomes more viscous resulting from heat loss and evolution of the dissolved gas, and thus movement of reservoir fluid slows down and stops at certain position inside the production string. In this paper, jet pumping has been selected and successfully applied to produce heavy oil from Lungu reservoir, Tarim Oilfield, with a maximum depth of 5950 m. Various power fluids have been examined for their capacities to reduce viscosity of the heavy oil in the production string. Hot water fails to reduce the viscosity of the reservoir fluid due to the significant heat loss along the wellbore, while adding chemicals to water (i.e., activated water) suffers from high material costs. Blending light oil with the reservoir fluid in the wellbore is found to optimally reduce viscosity of the reservoir fluid by more than 1600 times and has been applied in Lungu reservoir. Well configurations for jet pumping technique are designed and analyzed. A theoretical model is formulated to calculate the pressure, temperature, viscosity distributions along the production string, which are subsequently used to determine the key operational parameters, such as the quantity and pressure of the power fluid at the wellhead and the M ratio (ratio of the reservoir fluid to the power fluid). Sensitivity analysis indicates that the viscosity of the light oil and M ratio impose a significant impact on performance of the jet pumping. Field applications show that the jet pumping driven by light oil is a viable and efficient technique to lift heavy oil from the ultra-deep heavy oil reservoir.
Evaluation of Oil Compressibility Effects on Pressure Maintenance in Naturally Fractured Reservoirs Using Streamline Simulation
Authors: Tanaka Shusei , Arihara Norio , Al-Marhoun Muhammad
Published: July 2010

As naturally fractured reservoirs present wide ranges of geological characteristics and complex flow mechanisms between matrix and fracture, reservoir simulation is highly necessary to properly evaluate production performance. Pressure maintenance by gas and/or water injection is often required in naturally fractured reservoirs to control production GOR and to extract more oil from matrix rock. We studied by simulation particularly about effects of oil compressibility below bubble-point pressure on pressure maintenance and production performance.

We first developed and validated a 3-phase 3-dimensional dual-porosity model with the streamline method considering dissolved gas, capillary pressure and gravity. The fluid compressibility is a primary parameter that directly affects the reservoir performance. We accounted for compressibility effects with the total compressibility in the 3-D pressure equations, and with the effective density in the 1-D flow equations along streamlines. A flash-calculation algorithm was incorporated to treat the gas and oil phases correctly.

The oil and gas compressibility definitions presented by Perrine, that have been being used conventionally, have inherently a physical inconsistency such that oil compressibility below the bubble-point pressure increases with the increase of density, and that the mass of gas phase remains constant with changing pressures. To correct those, new derivation based on the basic compressibility definition was introduced.

Simulating peripheral water-injection with and without crestal gas-injection, results of pressure and production performance were compared for the new and conventional compressibility formulation. With the new compressibility, higher degrees of effectiveness were demonstrated in pressure maintenance. Gas injection also showed effectiveness in pressure maintenance, though it caused higher production GOR and a faster rise of water cut.
Finite Element Voupled Deformation and Fluid Flow in Fractured Porous Media
Authors: Lamb A. R. , Gorman G. J. , Gosselin O. R. , Onaisi A.
Published: July 2010

We present a finite element scheme which combines the dual permeability method (DPM) and the extended finite element method (XFEM) to simulate coupled deformation and fluid flow in fractured porous media. The scheme incorporates spatial variability in fracture properties without requiring the fracture to be discretized or aligned with the computational mesh. DPM is used to describe the fluid flow interaction between the porous matrix and fractures, whilst XFEM is used to address the discontinuous displacement field within elements which intersect fractures. The method is strongly coupled and solves the stress and flow equations simultaneously for each time increment.

DPM-XFEM uses the level set method (LSM) to define existing fractures and eliminates the need for their explicit discretization during simulation. The method performs well on coarse structured grids and does not require complex, difficult to generate meshes to conduct simulations. Comparison between the proposed method and the discrete fracture method (DFM) shows its ability to adequately determine the displacement and fluid pore pressure distribution within a fractured domain.
Friction Stir Welding: New Developments for Oil and Gas Industry
Authors: Steel Russell , Liu Qingyuan , Collier Matthew , Peterson Jeremy , Rowland Ray , Packer Scott
Published: July 2010

Friction stir welding (FSW) is a relatively new joining technology invented by The Welding Institute in 1991. The general use has been for welding soft, low melting materials such as aluminum. Advances in tool technology has allowed for the implementation of FSW into steel, stainless steel and nickel base alloys. The benefits of FSW include low heat input, elimination of solidification defects, the ability to join difficult and historically unweldable materials all while improving the mechanical properties over conventional welding processes. The oil and gas industry utilizes many specialized materials for performance and corrosion resistance. This paper will present and report progress on the different material properties and applications of FSW within the oil and gas industry.
Well Spacing Optimization for Tight Sandstone Gas Reservoir
Authors: He Dongbo , Jia Ailin , Jia Chengye , Guo Jianlin , Ji Guang
Published: July 2010

In the past five years, tight sandstone gas reserves amounted to almost 50% of the newly proved natural gas reserves of PetroChina Co., Ltd. and will be one of the main targets of natural gas production for a long term.

Means to determine the reasonable well spacing are the key topics in the development of tight sandstone gas reservoir. Relationships among well spacing, gas recovery and ultimate accumulation production are involved. For tight sandstone reservoir, because of its lateral permeability heterogeneity, flowing barrier which decreases the effective drainage area for gas depletion is frequently detected. Wide well spacing would result in low efficiency for producing reserves and decrease the ultimate recovery factor. Small well spacing would probably cause pressure conductance between adjacent wells and decrease the ultimate cumulative recovery of individual gas well, which would decrease the economic returns seriously. Thus, ways to determine the optimized well spacing is a great challenge in the development of tight sandstone reservoir.

Based on experiences in development of Sulige Gas field, reasonable well spacing can be properly determined from the following three aspects under precondition of maximum economic returns and ultimate recovery factor. The first one is that 3D geological model was utilized in the well pattern optimization process. Data of outcrops, cores and production of local infilling wells were used in the modeling. Micro-facies and reservoirs were accurately evaluated by determination of the scale of gas bearing sand bodies and its distribution. The second aspect is that through dynamic analysis of gas well production, three parameters including effective drainage area, recoverable reserves and influence area were calculated. The third one is that reasonable well spacing was determined on basis of the compromised researches of correlations between average investment, accumulative production rate, influence area and ultimate recovery factor.
The Novel Model for the Invasion of Particles and the Filtrate of Drilling Fluids
Authors: Jianhua Wang , Jinsheng Sun , Jie Feng , Xin Tan , Bai Lijuan Michelle
Published: July 2010

For high permeability sandstone, the invasion of particles and the filtrate of drilling fluids is proven as one of the key factors accounting for reservoir damage. However, it is difficult to determine the invasion depth of particles and the filtrate of drilling fluids by using mathematical model. The novel invasion models of particles and the filtrate of drilling fluids are built up in dynamic condition by the mass conservation equation and radial friction loss equation, especially for the models taking into account the external and internal mud cake at the same time. Parameters of models are determined by experiments of API filter loss and dynamic filtrate loss. The simulating results indicate that the invasion depth of particles is deeper when the core permeability is higher. The invasion depth of the filtrate is influenced seriously by the different pressure, the viscosity of filtrate, the permeability and thickness of external and internal mud cake. Howerver, permeability and fluid viscosity of reservoir have little influence on the filtrate invasion depth.

The zwitterionic polymer drilling fluids are optimized. In an addition, ideal packing approach is applied to the drilling fluids. The instrument of dynamic fluid loss test is used to evaluate return permeability. The test results indicate that the ideal packing approach can reduce the dynamic filtrate loss. It also can improve the return permeability and reduce breakthrough pressure. The predicted results of this model indicate that the invasion depth of particles and filter is deeper without bridging agents. Ideal packing approach can reduce formation damage.
Integrated Static and Dynamic Study to Determine Optimal Infill Potential of a High Water-Cut Oilfield with Bottom Aquifer in Sudan
Authors: Limin Zhao , Yang Liu , Dezhi Bian , Xianghong Wu , wei Li , Xinzheng Zhang
Published: July 2010

Fluvial sands with discontinuous interbeds and highly variable permeability patterns pose a significant challenge for further development of high water-cut oil fields with bottom aquifer in Sudan. To obtain an optimal strategy for further infill drilling a multi-disciplinary study of reservoir characterization and performance prediction was undertaken.

Data from vertical observation wells and deviated wells, combined with seismic horizon data and inversion data were used to characterize the spatial distribution of reservoir architecture and interbeds. Petrophysical properties (porosity and permeability) models were then stochastically simulated under such reservoir frameworks.

To avoid the distorted or zig-zag grids, vertical stair-step faulting upscaling method was taken to ensure that cells were orthogonal. Fine grids where interbeds most often occured were kept during upscaling to serve as vertical fluid flow baffle. The accurate coarse model that provided a realistic understanding of the lateral variation and distribution of reservoirs in inter-well areas were then taken as the base to effectively develop reservoirs.

During history matching, some scenarios were tested as alternatives in pursuit of a history match. The history matching procedure revealed the significance of interbeds as vertical prevention of water coning and permeability streaks as conduits to effectively drain reserves. Performance predictions for infill well cases are carried out based on the remaining oil distribution. The infill wells are optimized based on the incremental oil rate which can improve the cumulative oil production and recovery factor.