bluuebunny/crossref_metadata_2025 huggingface dataset:
Proving It – A Review of 80 Published Field Studies Demonstrating the Importance of Increased Fracture Conductivity
Authors: Vincent M. C.
Published: December 2007

Many engineers disregard laboratory reports demonstrating that the pressure losses across proppant samples are substantial. Similarly, it appears that the modeling studies warning of substantial productivity losses due to inadequate fracture conductivity have not been universally convincing.

Perhaps many practical frac engineers simply object to the theoretical nature of these arguments, when they quote one of the more influential orators of our time, Shania Twain,1 stating, "That don't impress me much."

Instead, many Petroleum Engineers prefer to see the economic benefit demonstrated in real reservoirs, and seemingly borrow a quotation from the film Jerry Maguire,2 stating, "Show me the money!"

The purpose of this paper is to summarize the results of over 80 field studies where well productivity was improved by increasing the fracture conductivity. The benefit of increased conductivity has been demonstrated in oil, condensate, and gas reservoirs in 50 regions around the globe. This benefit was documented by 250 authors representing over 70 companies. Increased conductivity has been shown to be beneficial in oil wells producing 2 bopd to 25,000 bopd, and in gas wells producing less than 1 MMCFD to over 100 MMCFD. Higher conductivity fractures were proven to improve the cash flow in carbonates and sandstones at depths of 2800 to 20,000 feet, and in low rate coal bed methane wells shallower than 1500 feet.

This review of industry experiences in a wide variety of reservoirs is not presented as a substitute for a comprehensive optimization study in a specific location. Instead, the following summary demonstrates that well productivity and profitability can frequently be improved with redesign of hydraulic fractures, despite the failure of many existing production models to predict those benefits.

These studies are presented to satisfy the following goals: 1)To verify that the extreme pressure losses observed in the laboratory and predicted by current fluid flow theory are real, i.e., "Proving It".2)To provide a list of fields, encompassing a wide variety of reservoir types, to assist engineers searching for results from an analogous field.3)To provide a number of field studies to which production models can be calibrated.4)To summarize the collective experience of over 250 authors, and incorporate what they have learned into future fracture designs.5)To demonstrate the relationship between fracture conductivity, well productivity, and cash flow, i.e., "Show me the money!"
Effect of Composition on Waterblocking for Multicomponent Gasfloods
Authors: Bijeljic Branko R. , Muggeridge Ann H. , Blunt Martin J.
Published: December 2007

During tertiary miscible gas injection direct contact between gas and oil can be prevented by water surrounding residual oil. The principal aim of our study is to assess the importance of this waterblocking phenomenon in multicomponent gas injection. We study this process using a multicomponent pore-scale model. Light components in the gas dissolve in the water and diffuse through the water to reach the oil. This causes the oil to swell. Eventually the oil swells sufficiently to contact the gas directly. However, components in the oil can diffuse into the gas, causing the oil to shrink and preventing the contact.

We apply our model to a variety of first-contact and multiple-contact miscible gas/oil systems from published field studies. Due to the low solubility of hydrocarbons in water, oil swelling and shrinkage can prevent direct contact for many days to years. We show that increasing the miscibility of injected gas, by, for instance, moving from a multi-contact miscible to a first-contact miscible displacement increases the time taken to achieve direct gas/oil contact. This leads to an extended two-phase region in the reservoir, even for a thermodynamically miscible gas flood.
Gas/Condensate and Oil Well Testing - From the Surface
Authors: Fair Chris , Cook Betsy , Brighton Tom , Redman Michael , Newman Stacy
Published: December 2007

Since Cullender and Smith(1), surface pressures have been used to calculate bottomhole pressures on shallow, dry gas wells. If the original Cullender and Smith equations are modified to account for produced liquids, the correlation may be extended to gas/condensate wells that are single-phase in the well bore. Single-phase liquid wells (water injectors and oil wells above the bubble point) can also yield accurate well test results from the surface. Testing from the surface reduces the cost and eliminates the risk of running tools into well bores. Surface testing also allows the testing of high-pressure/high-temperature wells that cannot be tested with a downhole gauge because of harsh conditions. Thus, to reduce the cost and risk (or when no other option is available), many operators have chosen to run their pressure transient tests from the surface on single-phase wells.

Recently, it has become possible to test most naturally-unloading gas/condensate and oil wells from the surface. This is due to advances in multi-phase wellbore modeling along with improved pressure transducer quality. Of these, the most important advances are the improvements in transducer manufacture and calibration that make it possible for a surface pressure gauge to be effectively isolated from ambient and wellbore thermal transients. Although the technology exists to get representative reservoir data from the surface, testing procedures in multi-phase wells have to take into account the fluid's behavior in the well bore. With this in mind, the purpose of this paper is to propose guidelines for testing multiphase wells from the surface. First, the general framework of the surface-to-bottomhole pressure calculation will be presented. Next, multi-phase wells will be categorized based on the type of fluid and the behavior of the fluid both in the reservoir and in the well bore. This categorization will be the basis for both surface testing candidate selection and recommended test procedures. Afterwards, wellbore phase and temperature modeling will be discussed. Next, instrumentation requirements will be presented. Finally, field data comparing calculated bottomhole pressures from surface gauges to measured bottomhole pressures from downhole gauges (and the subsequent analysis) will be presented for both a gas/condensate and an oil well.

These examples will be used to demonstrate that in order to test a multi-phase well from the surface, a thermally compensated quartz pressure gauge must be used in conjunction with a properly designed and executed test procedure. An explanation will also be provided as to why the best test that can be performed on a well to determine skin, permeability and the size of a reservoir is a constant-choke drawdown.
Managing Turbulent Technology for Exploration and Production Success
Authors: Wye Robin
Published: December 2007

Strategic technology innovation is increasingly being seen as a key value driver for leading companies across many industries - it is no longer sufficient to focus solely on incremental advances in technology, processes, or business models.

From analysis of leading technology innovators, across multiple industries, we have developed a six-part model for management of turbulent technologies (MTT) – those that have the capability to drive a step-change in corporate performance.

We also show evidence that analysts are increasingly looking at technology to deliver the next wave of upstream value creation – making the MTT model highly relevant for shareholders and managers.

We describe key elements of the model, and present examples of effective technology management from inside and outside the upstream industry.

Finally, we highlight the main steps required to develop a model for management of turbulent technology, and conclude that upstream oil and gas companies adopting the MTT model can potentially make significant gains in value and enhance their competitive position.
Pore-Scale Modeling of Three-Phase Flow in Mixed-Wet Systems
Authors: Piri Mohammad , Blunt Martin J.
Published: December 2007

We use a pore-scale network model of three-phase flow to compute relative permeabilities, saturation paths and capillary pressures for a variety of displacement processes. The model is based on a random network of pores and throats with triangular, rectangular and circular cross-sections that represent the complex pore space observed in sandstones. We model wettability alteration after primary drainage and allow any values for the advancing and receding oil/water, gas/water and gas/oil contact angles. Multiple phases can be present in each pore, in wetting and spreading layers, as well as occupying the center of the pore space. In all, twenty different generic fluid configurations for two- and three-phase flow are analyzed.

With a network based on a description of Berea sandstone we can predict relative permeabilities for two-phase flow in a water-wet system and waterflood recoveries for mixed-wet media. We then predict the steady-state oil, water and gas three-phase relative permeabilities measured by Oak.1 We demonstrate that the predictions obtained by the network model compare favorably with those obtained using standard empirical relative permeability correlations.

We then study gas injection into media of different wettability and interpret the results in terms of pore-scale displacement processes.
Field Scale Research on Gas Chamber Pumps
Authors: Hernandez Ali , Reyna Marcelo
Published: December 2007

Recent experimental studies on intermittent gas lift have shown that the lift efficiency of this method decreases drastically as the viscosity of the fluid to be lifted increases. As the viscosity increases more gas is needed to keep the fallback losses at a minimum. One way to get around this problem and eliminate fallback losses is to implement the use of Gas Chamber Pumps (GCP's).

GCP's are highly appropriate for shallow wells producing heavy oil in places where high-pressure injection gas is available. That is the case of some wells in Lake Maracaibo and in some places in the eastern oil fields in Venezuela that are currently producing oil of 14 to 23° API from reservoirs located at depths between 2000 and 3500 ft.

A variety of different GCP configurations can be found in the literature, from highly complex and compact units to simple types of completion that can be implemented with minor changes of current gas lift completions. The advent of simple and highly reliable programmable surface controllers is making it possible to simplify subsurface completion. The simplicity of these new completions implies a new and economical way of implementing GCP's where they are appropriate. Furthermore, a new mathematical model to estimate the liquid production and gas consumption of a well producing with a GCP was developed recently and presented in the literature (paper SPE 69401).

A new field scale research conducted on GCP's is presented in this paper and a comparison of the actual measurements with the mathematical model outcome is included.
Use of Settable Spotting Fluid Improves Expandable Casing Process—Case History
Authors: Owoeye Oladele O. , Onwuta Victor O. , Erivwo Ochuko E. , Griffith James , Nida Ron
Published: December 2007

This paper presents laboratory and field data for using a settable spotting fluid (SSF) to help improve the subterranean zonal isolation of primary cement jobs on expandable liner installations. A SSF can add value to the well construction process when well conditions for cementing are less than optimal; i.e., low annular velocity, no pipe movement, poor casing centralization, or poor mud conditions. Many of these unfavorable conditions are present when expandable casing is installed.

Past SSF designs used blast-furnace slag and were limited to temperatures less than 90°F (32°C). The new SSF incorporates a hydraulic material with a non-blast furnace slag and is formulated for water-or oil-based wellbore fluids. Although the new SSF is optimal for displacement in the cementing process, the SSF will set to a state for providing zonal isolation if it is bypassed during the cement displacement process. Depending on the time required to run and expand the casing, the SSF can be formulated to remain liquid for a few hours or as long as three weeks. However, the high pH condition and heat of hydration from the placed cement in the annulus can accelerate the set of the SSF to a few hours.

The achievement of a near-100% annular seal occurs even when poor cementing conditions are present and without the use of rheologically tuned spacers. Job data from field trials also show improved shoe integrity and higher pipe-to-cement bond, echoing the results from the laboratory tests.
Feasibility Assessment of a New Approach for Integrating Multiscale Data for HighResolution Reservoir Characterization
Authors: Reeves Scott R. , Mohaghegh Shahab D. , Fairborn John W. , Luca George
Published: December 2007

The ability to accurately and fully characterize subsurface oil and gas reservoirs remains an elusive target for the energy industry. By accurately we mean with less uncertainty and at a higher spatial resolution than today's state-of-the-art, and by fully we mean in continuous, threedimensional space. The benefits of achieving this objective are obvious; field development plans and enhanced recovery operations can be optimized, and bypassed hydrocarbon pools can be identified and targeted for production. Ultimately, this should translate into an improvement in ultimate recovery factors from existing fields from the current (U.S.) average of only about 35%.

A research project funded by the U.S. Department of Energy has recently been completed to demonstrate the feasibility of a new approach to achieve the above objective. In summary, a series of relationships, founded on artificial intelligence technology, have been established (both in this project and by others), between data of different scales and type, including conventional logs, reservoir imaging logs, cross-well seismic, and surface seismic. Specifically, relationships between conventional logs and imaging logs have been demonstrated, as have relationships between conventional logs and cross-well seismic, and finally between cross-well and surface seismic. Through their integration, a fully 3D reservoir image should be possible, directly in the engineering terms required for reservoir flow simulation (i.e., porosity, fluid saturations, and permeability), at an improved resolution over surface seismic alone, and with less uncertainty than geostatistical methods alone. The specific advantages of the new approach include: Improved vertical resolutionEliminates need for seismic attribute inversionInclusion of intermediate scale data (e.g., cross-well tomography) increases constraints and reduces uncertainty of reservoir descriptionFinal product presented in terms of reservoir engineering parameters needed for flow simulation

While the work performed to date has demonstrated the technical feasibility of achieving a next generation of highresolution reservoir characterization-using today's data collection capabilities-it has yet to be validated in an integrated manner at a single field, and reconciled with field performance via reservoir simulation. Further research along these lines, aimed at both improving and demonstrating the technology, and also funded by the U.S. Department of Energy, is currently underway. This paper presents the work performed to demonstrate the technical feasibility of the new approach for high-resolution reservoir characterization.
Natural Gas Liquids and LNG Production from Crudes and Wet Gases
Authors: Desouky S. M. , King Saud U. , Macary S.
Published: December 2007

The term Natural Gas Liquids (NGL) refers to a mixture of gases (ethane, propane butanes and pentanes), that can be extracted by multi-stages of compression and cooling. This work developed a mathematical model to simulate the production of NGL from Arab crudes and wet gases. The model consists of three sections. The first is the partial vaporization unit, in which the number of stages (N) depends on the determined optimum conditions. Second: partial condensation unit, from which the separated liquid passes into the third section-fractionation unit (demethanizer), where NGL is produced. The model accounts for the effects of the main operational variations such as operating conditions (pressure and temperature), number of stages to separate gases from crude (N), number of stages for liquid separation from associated and wetted gases (M), number of trays in demethanizer (T) and refrigeration energy (E).

The model gives optimum solutions for processing crude oils of different API gravity and for various feed conditions and gas-oil ratios. The applicability of such a model will be advantageous, particularly in Arab Countries, where the separator off-gases are flared.
Utilization of Geomechanics for Medusa Field Development, Deepwater Gulf of Mexico
Authors: Chhajlani Richin , Zheng Ziqiong , Mayfield David , MacArthur Bruce
Published: December 2007

The scope of applied geomechanics in the petroleum industry has been on the rise over the past decade. Geomechanics analysis has shown to increase the overall value to various projects and create positive technical synergies between various groups involved with project development. This paper highlights a comprehensive geomechanics study carried out on a deepwater Gulf of Mexico (GoM) field for optimizing field development with respect to critical drilling, completion and reservoir issues. A detailed and well-calibrated wellbore stability model applied to the Medusa field has shown to reduce the drilling operational costs by enhanced well planning. The log-based geomechanics models used to evaluate sand production and pressure dependent pore volume compressibility have aided in reducing project risks and increasing project life. The intent of the paper is to show the practical risk reduction and cost savings that are possible through geomechanics analyses in high-cost, high-risk projects in deepwater arenas such as the Gulf of Mexico.
Influence of Temperature and Clays/Emulsion Microstructure on Oil-Based Mud Low Shear Rate Rheology
Authors: Herzhaft Benjamin , Rousseau Lionel , Neau Laurent , Moan Michel , Bossard Frederic
Published: December 2007

Oil Based Muds are very complex fluids composed from water, oil, organophilic clays and various additives. Their very good filtration and lubricating properties make their use beneficial in numerous drilling operations. Deep offshore operations may present phases using Oil Based Muds as drilling fluids. In these operations, the mud will experience very low temperature (down to 0°C) and low shear rate when flowing through the riser. It is therefore of primary importance to control muds rheological properties under such conditions. This work presents a rigorous experimental study of Oil Based Mud rheological properties using scientific rheometers. Temperature dependence and low shear rate behavior are specially studied. Due to their complex nature, Oil Based Mud rheological properties will be extremely dependant on the microstructure of the composition. Characterization of this microstructure has therefore been sought during this study.

Several Oil Based Muds compositions have been investigated. Flow curves have been established with a precise and reproducible procedure at temperatures varying from 0 to 80 °C. For an offshore designed composition, a specific behavior at low shear rate has been detected; two different regimes can be seen: a newtonian behavior at low shear rate and an Herschell-Bulckley behavior at higher shear rate, the limiting shear rate value between the two regimes being dependent on temperature. Experiments on partial compositions (partial muds with/without solids, with/without clays) have shown that the specific clay used in this composition is responsible for this particular behavior at low shear rate. Oscillatory rheometry measurements have confirmed the existence of these two different regimes. CryoMeb and microscopic observations have allowed to estimate the size of the emulsion droplets and the clay particles; a simple energetic and structural model is proposed that fit well the data. Finally, a comparison is made between these experiments and those obtained using Fann35 rheometer; concluding that classical Fann35 measurements induces large error for low shear rate rheology.
Creating and Nurturing a Knowledge Sharing Culture in a High Performance Technical Group
Authors: Balnaves Charles , Busch Barbara
Published: December 2007

The Petroleum Engineering function at BHP Billiton bears primary responsibility for providing estimates of the company's oil and gas reserves and an understanding of the uncertainty surrounding them. Forecasting of production profiles, efficient completion design and analysis of data to calculate the number of wells and their placement ensure effective production. This paper is focussed on a hidden but critical success factor for the function - its knowledge sharing culture.

Since 1998 the business plan for the function has been specifically designed to meet the organisation's strategic needs by creating a global knowledge-sharing group to ensure that the 120 (approximate global contingent) staff are able to provide excellent, speedy and reliable results. This paper outlines how we have moved in four years from a largely regional, functionally isolated group to one which can move staff across the world quickly for short term projects, execute complex technical work successfully in virtual teams and respond within 24 hours (in many cases) to each others requests for assistance. Sharing our knowledge has become a natural part of the way we work.

This paper outlines the need for change and for alignment to the organisation's business imperatives. It also covers the issues that we faced in the implementation of the plan to move to the desired culture and the balance between organisational growth, maintenance of size and reduction in various offices. The vision, strategy and execution plans for practical implementation of cultural change are outlined along with examples of our success and remaining challenges.
Downhole Emulsion Problem, The Causes and Remedy, Ras Budran Field
Authors: Aziz Hany M. Abdel , Darwish Sameh F. , Abdeen Fathalla M.
Published: December 2007

Ras Budran (R/B) field is located 5Kms. offshore at the eastern coast of the Gulf of Suez and consists of a massive Nubian Sandstone Reservoir compartmentalized by partially major faults. The field is undersaturated and production is maintained by gas lifting while the pressure is supported by a combined water flood and limited aquifer drive.

The R/B produced crude oil has an intermediate base with asphaltene content ranging from 10–15% wt and an average API Gravity 25°.

With the increase in water production and injected seawater breakthrough a very viscous tough emulsion was formed in some wells, causing production problems. Also, due to scale deposition, calcium carbonate and sulphate, the hydrochloric acid and other scale dissolvers were applied to clean the tubing and the formation. Some of these additives have an adverse effect on the emulsion viscosity and cause asphaltene deposition.

The paper presents the study carried out to identify the problem and find a solution for it. The study includes: ◊The rheological properties of the emulsion at different downhole conditions; shear rates, temperatures and water contents at different salinities.◊The effect of the different chemicals used for scale removal and inhibition on the asphaltene deposition and the produced crude oil emulsion viscosity.◊The effect of the flow improver products; demulsifier, Asphaltene dispersant, viscosity and drag reducers…etc. on increasing the fluidity and reducing the drop in pressure of the produced crude oil emulsion.

The study results showed that the hydrochloric acid causes asphaltene deposition and tough emulsion formation. Also the increase in the water content form a very tough/viscous emulsion at a certain percentage, which is defined as the inversion point, below and above this percentage the emulsion viscosity is reasonable.

The injection of the flow improver chemicals through the gas lift valves could reduce the emulsion viscosity.
Optimized Decision Making through Real Time Access to Drilling and Geological Data from Remote Wellsites
Authors: John Zachariah , Ahsan Abul , Reid Ian
Published: December 2007

Effective two-way communication and data flow between rig and office is essential to optimise decision making in offshore operations. Traditionally, during drilling operations, engineering, geological and formation evaluation while drilling (FEWD) data was only available at the Operator's office via morning and afternoon reports, email, shared folders and telephone. Information technology has now evolved to a stage where office-based geologists and engineers can monitor and evaluate wellsite data in real time using the Internet and any standard web browser. This enables domain experts to provide more effective support to the wellsite staff especially when critical decisions are to be made in a timely manner.

This paper describes how modern information technology such as InterACT (Formerly called InterACT Web Witness: or IWW) facilitates collaborative work in real-time on data being acquired from remote drilling wellsites. The availability of data real-time does create a paradigm shift in the way the asset team and contractors utilize data for early decisions. Challenges, benefits, and lessons learnt on the implementation and application of this technology are highlighted through examples where this technology was used namely: Echo/Yodel development drilling campaign (Woodside Energy Ltd.) for Geosteering Decisions and Melville-1 exploration well (Bass Strait Oil Company Ltd) for monitoring drilling, FEWD and wireline logging.

Experiences from these two projects gained by Schlumberger can be utilized by other companies to put in place a data flow model incorporating real time data.
Numerical Simulation Studies of Thermally-Induced Gas Production from Hydrate Accumulations with No Free Gas Zones at the Mallik Site, Mackenzie Delta, Canada
Authors: Moridis G. J.
Published: December 2007

The Mallik site represents an onshore permafrost-associated methane hydrate accumulation in the Mackenzie Delta, Northwest Territories, Canada. This study focuses on gas production at the Mallik site from hydrate deposits that are underlain by either a free water zone or by an impermeable boundary. The production analysis was conducted using a numerical simulator that can model the non-isothermal CH4 release, phase behavior and flow under conditions typical of CH4-hydrate deposits by solving the coupled equations of mass and heat balance. The simulator can describe any combination of the possible dissociation mechanisms (i.e., depressurization, thermal stimulation, salting-out effects and inhibitor effects). Accumulations with a CH4-hydrate saturation of at least 50% were studied. Dissociation was induced mainly by a combination of thermal stimulation and depressurization as hot fluids circulated between injection and production wells. The effects of salinity and of pressure changes at the wells were also accounted for. The production strategy resulted in a zero net water production. The simulation results indicated that the amounts of CH4 released from the dissociating hydrate deposits is sensitive to the hydrate saturation, the initial temperature, the specific enthalpy and the flow rate of the circulating fluids.
Characterization of Fracture Permeability by Using a Fractal Model
Authors: Murata S. , Mitsuishi H. , Saito T.
Published: December 2007

Correct estimation of fracture permeability is a key factor for the successful development of fractured reservoir. Based on the Kozeny-Carman equation, we have described the deviation from the conventional cubic law of the fracture permeability by using a fractal model of fracture surfaces. In order to confirm the validity of the description, we carried out several laboratory experiments and numerical simulations to the artificially prepared fracture specimens whose geometric surface properties were controlled by the fractal model. Consequently, the validity was confirmed and it was cleared that the two-dimensional tortuosity and the shape factor affect on the deviation from the cubic law more remarkably than the fractal dimension and the steepness, and therefore, these parameters are very important to estimate the deviation from the cubic law of fracture permeability correctly. Furthermore, it was cleared that fluids flow through a fracture with selecting the large aperture regions and the tortuosity increases with increase in the contact area of the fracture.
Variable Saturation Exponent Effect on the Determination of Hydrocarbon Saturation
Authors: Hamada G. M. , AL-Awad M. N. , Alsughayer Alsughayer
Published: December 2007

An accurate determination of initial oil in place in the early life of reservoirs or an evaluation of a developed reservoir is required to well estimate the hydrocarbon volumes. Modified Archie formula (Sw = (a Rw / ϕm Rt)1/n) is the basic equation to compute water saturation in clean formation or suitable shaly water saturation model in shaly formation. The accuracy of water saturation value for given reservoir conditions depends on the accuracy of Archie parameters a, m and n. The terms of Archie relationship have been subjected to many laboratory investigations and even more speculations. There are many factors affecting porosity exponent, m, saturation exponent, n and tortousity factor, a. Therefore, it is very difficult to fix Archie parameters and neglecting reservoir characteristics; rock wettability, formation water salinity, permeability, porosity and fluids distribution. This paper presents a new technique to determine Archie parameters a, m and n. The developed technique is based on the concept of three dimensional- regression (3-D) plot of water saturation, formation resistivity and porosity. This 3D technique provides simultaneous values of Archie parameters. Also, the 3D technique overcomes the uncertainty problems due to the separate use of formation resistivity factor- porosity and water saturation equations to get a, m and n parameters.

Two field examples are given to show the applicability of the 3-D technique in comparison with three other techniques: 1) common values of Archie parameters, 2) conventional technique and 3) core Archie parameter estimation (CAPE) technique. The comparison among the four techniques has shown that 3-D technique provides an accurate and physically meaningful way to get Archie parameters a, m and n for given core samples. Water saturation profiles, using Archie parameters obtained from the four techniques, have been obtained for the studied section in the wells. These profiles have shown a significant difference in water saturation values. This difference could be mainly attributed to the uncertainty level for Archie parameters from each technique. The effect of saturation exponent on the accuracy of water saturation computation was tested using Archie's parameters derived from conventional technique and 3-D technique in the two wells.
Reservoir Monitoring with Carbon-Oxygen Logging Through non Characterized Dual Concentric Casings: A Case Study
Authors: Wilson Michael
Published: December 2007

Many reservoirs in the North West Shelf of Australia have low salinity formation water (in the order of 20ppk), which makes detection of water contact movements difficult with traditional pulsed-neutron capture logging techniques (sigma logging). Carbon-Oxygen logging has proven very successful in reservoir monitoring in such cases. The characterization of the response of these measurements relies on a database of thousands of physical models of lithology, formation fluids, borehole fluids and wellbore completion characteristics. However, not all completions and scenarios have been modeled physically, and built, due to the infinite number of possibilities. Monte Carlo modeling is used to interpolate between common situations, but there are variations, such as in this case, dual concentric casings, that fall outside the present database.

The well on the North West Shelf of Australia involved in this case study, was originally completed as a monitoring well, with only the top of the reservoir sand perforated and producing dry oil. The completion has a 4 ½" tubing cemented inside a 7" liner, i.e., a dual concentric casing. Nearby wells in the same field are also perforated in the lower sands, from which they are producing. The objective of the carbon/oxygen logging was to ascertain fluid movement (oil water contact) in the lower zones and utilize this information to optimize the subsequent perforation intervals thus accelerating the production of the well without increasing water flow.

This paper describes a methodology and case study to plan, acquire and extract qualitative answers from carbon-oxygen logging in the dual-concentric casing scenario, in order to make a near real time decisions on the perforations to follow. The methodology utilized in this well can be used for job planning, execution and interpretation of similar, non-characterized wells.
Applying MAK Gas-Water Relative Permeability Correlations to Predict a Gas-Condensate Relative Permeability and Production Performance (Case Study)
Authors: Mulyadi Henny , Mason Tom , Steer David
Published: December 2007

An analytical correlation to describe relative permeability is extremely useful in the absence of laboratory measured data, or when a general representative fluid flow is required. Previously, experimental work has been done to develop new correlations to predict gas-water relative permeability (RP) data for various permeability and porosity media. The newly developed technique consists of quick laboratory measurements to measure end-point saturations and newcorrelations to predict gas-water relative permeability behaviour.

These differ from previous work because they honour the reservoir's rock and fluid properties – such as reservoir permeability, porosity, interfacial tension and gas density. The effectiveness and practicality of applying these new correlations to simulate laboratory measured gas-water relative permeability data (for various permeability and porosity cores) has been demonstrated in SPE 71523.

To conclude, as part of a doctoral dissertation, the correlations were tested on simulation models. The aims of this work segment were twofold: To investigate the applicability of the newly developed analytical correlations to reservoir simulation and their impact on history matching and forecasting of reservoir production. No attempts were to be made to re-match the production history.To investigate the effect of applying the correlations pre and post-upscaling of static reservoir model. This part of the investigation demonstrates that in situations where the upscaling of the static model has resulted in significant distortion of the K and ϕ relationship, application of Mulyadi-Amin-Kennaird (will be refered to as MAK through out this paper) correlations, or similar, would be erroneous.

The new correlations were used to generate several sets of gas-water relative permeability data to replace the corresponding history-matched relative permeability data in the pre-upscaled and a post-upscaled producing gas-condensate reservoir models. The implications of the new correlations were assessed from the model's historical and forecasted reservoir production performance.

The results of the specific cases investigated demonstrated that while the new correlations did not significantly affect the history-matched period, it did havesignificant impact on the forecasted production profiles and ultimate recovery. Although these are not unexpected, the differences were significant enough to warrant attention; in particular the manner in which such correlations are used to populate dynamic models.
Smart Well Solutions for Thin Oil Rims: Inflow Switching and the Smart Stinger Completion
Authors: Jansen J. D. , Wagenvoort A. M. , Droppert V. S. , Daling R. , Glandt C. A.
Published: December 2007

The production of oil from horizontal wells in thin rims sandwiched between gas and water is notorious for coning problems. There is a strong tendency for early gas or water breakthrough at the heel, especially if the pressure drop over the length of the well is in the same range as the drawdown. We present two conceptual solutions to counteract the negative effect of well bore pressure drop through the application of downhole measurement and control. One solution concerns inflow switching in a segmented well bore and allows for coning control after breakthrough has occurred. The other solution aims at preventing breakthrough as long as possible. This is achieved by flattening the drawdown profile along the well through controlling inflow at one or more points in an extended stinger. The feasibility of the solutions was demonstrated through numerical simulations over a range of reservoir and well bore parameters. Implementation would require further development of downhole water and gas detection capabilities.
New Friction Factor Correlations for Non-Newtonian Fluid Flow in Coiled Tubing
Authors: Zhou Y. , Shah S. N.
Published: December 2007

This paper presents a complete set of friction factor correlations for both Newtonian and non-Newtonian fluids in laminar and turbulent flow in coiled tubing. The friction factor correlation for non-Newtonian fluids in laminar flow is obtained based on theoretical analysis and numerical solutions of the flow equations of a power-law model fluid in curved pipes. The empirical correlation for non-Newtonian fluids in turbulent flow is developed based on full-scale experiments of polymeric fluid systems in various 1", 1–1/2", and 2–3/8" coiled tubing reels. To consider the effect of pipe roughness in coiled tubing, a modified correlation is proposed by combining the Srinivasan et al. correlation for smooth curved pipe and the Chen correlation for rough straight pipe. Examples are given to illustrate the applications and accuracies of the newly developed correlations.
Quantifying the Fracture Mechanics Properties of Rock for Fractured Reservoir Characterization
Authors: Olson Jon E. , Holder Jon , Rijken Peggy
Published: December 2007

Natural fractures are important conduits for fluid-flow and can control the deformational behavior of rock. The accurate evaluation of natural fracture geometry in the subsurface is difficult because of the sampling problems inherent to wellbores and indirect investigation methods such as seismic. Because of these limitations in observational capability, predictive models are needed to provide more constraint on natural fracture characteristics. One approach is to look at the mechanics of fracture propagation in sedimentary rock as controlled by subcritical crack growth (also known as stress-corrosion cracking). We have measured the subcritical fracture properties of numerous sedimentary rocks, including core samples from petroleum reservoirs, in conjunction with detailed petrographic analysis. Our preliminary results suggest that carbonates and sandstones tend to have very different subcritical fracture properties, and the variation in sandstone properties can be linked to grain and cement mineralogy and volume fractions.
Estimation of In-Situ Rock Parameters From Pressure Time Series
Authors: Schulze K. C. , Brudy M. , Kjørholt H.
Published: December 2007

For a borehole of the Gullfaks field in the northern North Sea 60 days borehole pressure data of two successive registrations (hereafter parts I, II) were analyzed. From correlation with theoretical ocean tides a loading efficiency γ of 0.35-0.40 and of 0.16-0.19 were obtained for parts I and II, respectively. No influence of air pressure or earth tides could be resolved. Assuming an undrained Poisson ratio vuranging between 0.30 and 0.36 and assuming that the vertical loading results in an areal strain εa of the same magnitude as the vertical strain εV a Skempton ratio B of about 0.45 for part I and of about 0.20 for part II were derived. B values are somewhat higher assuming smaller εa. The notably different values for γ and thus, B can be explained by a significant change in reservoir properties, which was induced by several injections in the borehole in the time between the two registrations.
Controlled Acid Jet (CAJ) Technique for Effective Single Operation Stimulation of 14,000+ ft Long Reservoir Sections
Authors: Hansen J. H. , Nederveen N.
Published: December 2007

Horizontal wells with continuous reservoir sections between 10,000 and 20,000 ft are being used for the development of the laterally extensive low permeability chalk in the Dan/Halfdan oil accumulation, offshore Denmark.

The concept, design and practical experiences from an efficient and effective completion and stimulation method, Controlled Acid Jet1 (CAJ), which has been developed to stimulate very long horizontal well sections in a single operation, is described. It is a non-cemented liner, with a limited number of unevenly spaced holes (perforations) which ensures efficient acid stimulation of the complete reservoir section, provided the acid is pumped at sufficiently high rates.

The CAJ liner has in several ways set new standards for the completion and stimulation of long horizontal wells. The most significant achievement with the CAJ liners is the remarkably effective acid coverage with efficient stimulation of reservoir sections up to 14,400 ft in a single operation. This is more than 20 times the interval length covered during matrix acid stimulation in a traditional cemented and perforated liner.

The CAJ liner completion and stimulation concept has proven to be efficient, uncomplicated to install and very cost effective. Currently, 35 CAJ liners are producing from more than 220,000 ft of reservoir sections in the Dan West Flank/Halfdan field.

The production performance of the wells completed with the CAJ system is concluded to be superior to the performance of wells completed with conventional systems.
Performance of Cased-Hole Sand-Control Completions in High-Rate Wells — A Case Study from the Girassol Field, Angola
Authors: Delattre Eric , Mus Emmanuel , Van Domelen Mark , Azer Alfred , Payer Nicolas
Published: December 2007

Wells in the Girassol field, offshore Angola, are in the deepest water and contain some of the highest transmissibility reservoirs completed in west Africa. These conditions have presented significant challenges for well completions in this field. While the completion strategies employed to date have included both openhole and cased-hole (OH and CH) wells, concerns existed before the development phase regarding whether the cased-hole completions were a viable option. These concerns were primarily a result of (1) the potential loss of flow efficiency in the perforations and near-wellbore region caused by turbulence effects in these high-rate wells and (2) the ability to successfully place the frac packs in these high-mobility reservoirs.

This paper provides an overview of the Girassol field, along with the factors and desired benefits that led to the decision to employ CH completion techniques. The paper also describes the methods used to help mitigate the non-Darcy flow effects in the completions, details the design and implementation of the completions, and presents the well test and production results.
Selection of EOR/IOR Opportunities Based on Machine Learning
Authors: Alvarado Vladimir , Ranson Aaron , Hernández Karen , Manrique Eduardo , Matheus Justo , Liscano Tamara , Prosperi Natasha
Published: December 2007

The Venezuelan National Oil Company, PDVSA, has dedicated a sustained effort to adapt EOR/IOR technologies to rejuvenate a large number of its mature fields. The first step towards achieving this objective was to select cost-effective technologies suited for conditions of Venezuelan reservoirs. The current strategy for screening EOR/IOR applications is based on the Integrated Field Laboratory philosophy, where a representative pilot area of a number of reservoirs is selected to intensively test EOR/IOR methods, such as WAG injection (water alternating gas) and ASP (alkali polymer surfactant), currently underway. Two problems with this approach are the lack of objective rules to define a reservoir type and the project completion time. In general, the trouble with using expert opinion is that it tends to be too biased by operational experience. It is known that the success of a given EOR/IOR method depends on a large number of variables that characterize a given reservoir. Therefore, the main difficulty for selecting an adequate method is to determine a relationship between reservoir characteristics and the potential of an EOR/IOR method. In this work, data from worldwide field cases have been gathered and data mining was used to extract the experience on those fields. Here, a space reduction method has been used to facilitate the visualization of the needed relationship. Machine learning algorithms have been utilized to draw rules for screening. To illustrate the procedure, several Venezuelan reservoirs have been mapped onto the extracted representation of the international database.
Uses and Abuses of Equations of State
Authors: Kawahara Hiroshi , Hiraiwa Takeshi , Yoshida Koichi , Watanabe Makoto
Published: December 2007

Equations of state (EOS) are perhaps the most abused and mis-used concept in compositional reservoir simulation. It is believed that the EOS are often need adjusting or tuning and the well-tuned EOS can capture all phase behavior in the reservoir simulation. However, the well-tuned EOS can not calculate appropriately in the reservoir simulation because the matching objectives, the existing PVT experiments, are not enough to cover all necessary pressure, temperature, and components.

An EOS for CO2, hydrocarbon gas and sour gas injection is tuned for a reservoir fluid offshore Abu Dhabi. The universal EOS for gas injection, EOS-U8, was originally developed as EOS-H18 for hydrocarbon gas injection (both sour and sweet). After the EOS-H18 was developed, additional PVT experiments, swelling tests with CO2 and other two hydrocarbon gases, were conducted and the EOS-U8 was tuned in order to capture the phase behavior of the reservoir fluid and all candidate injection gases. The new, tuned EOS is available for evaluating gas injection, including direct comparison between injection gases. Our tuning procedure for an EOS, including laboratory data selection, is applicable to other reservoir fluids.

The Flash calculation is compared utilizing the tuned EOS using all or selected laboratory data. Limited laboratory data may mislead the tuning process of the EOS parameters for extensive application of the EOS. The methods that gave the best match are also discussed.

Three commercial software for generating EOS parameters were compared for performance, accuracy, and ease of use.

The advantages and disadvantages of three commercial EOS PVT programs are compared. The interface and function of the programs are also evaluated. Three EOS based PVT programs show different results with high concentration of CO2 or H2S using the tuned EOS parameters. Therefore, special cares are required for importing EOS parameters form other EOS programs. The most appropriate ways to use the EOS developed by current software products are discussed. The results from this comparison study of EOS based PVT programs are useful for selecting PVT programs.

Finally three EOS (EOS-H8, C8, U8) were compared in the compositional reservoir simulation. The tuned EOS with the selected laboratory data shows different results in the reservoir simulation using the EOS-U8. It is recommended that EOS should be tuned utilizing as much as PVT experiments.