bluuebunny/crossref_metadata_2025 huggingface dataset:
Seismic Facies Analysis for Fracture Detection: A Powerful Technique
Authors: Bloch Gérard , El Deeb Maged , Badaam Hussein , Cailly Frédéric , Iecante Gael , Meunier Antoine
Published: December 2007

Fractured reservoir analysis requires an accurate delineation of fracture corridors, as well as an estimate of the fracture density. Fracture corridors are often closely associated with faults, large and small. 3D seismic data is of great help for minor "sub-seismic" fault detection and characterization, small faults being often expressed as very subtle zones of deformation (discontinuities), with no obvious offset of seismic reflections.

A large number of seismic attributes are known to highlight discontinuities. They can be horizon-based, such as curvature, dip, edge, azimuth or based on the 3D seismic trace variability in a given neighborhood such as "coherence-type" attributes or computed after Fourier or Hilbert transform as instantaneous phase or frequency.

This paper proposes, in a large Upper Cretaceous carbonate reservoir onshore UAE, to use jointly a set of selected "fracture relevant" attributes in a multi-variable statistical process called Seismic Facies Analysis (SFA). The resulting seismic facies map delineates areas spatially oriented towards two directions that are consistent with the general structural knowledge of the field. Analyzing seismic attribute distributions within each seismic facies gives a preliminary interpretation of these seismic facies in terms of fracture density. The validation of this interpretation with well data (BHI, core and dynamic data) delivers an accurate map of fracture occurrence. This map is then used to interpret structural lineaments and constrain stochastic realizations of the fracture model.
Multiphase Flowmeter and Production Logs Diagnose Well Response in an Onshore ADCO Field, Abu Dhabi
Authors: Khoori A. , Bekkousha M. A. E. K. , Pinguet B. G. , Turna E. P. , Koshy T.
Published: December 2007

In early 2002, Abu Dhabi Company for Onshore Oil Operations (ADCO) ran a production-logging program on a high-performance onshore well with an intensive surface welltesting program. This involved running a multiphase flow meter in combination with a calibrated gauge tank and a test separator, in order to qualify the metrological performance of the multiphase flow meter. The objectives were to determine well productivity, establish the flow profile of the reservoir, and assess the performance of the multiphase flowmeter.

This paper describes the benefit of advanced multiphase flowmeter technology and the verification of its performance accuracy against production logs and surface equipment.

In addition to the accuracy computations, the repeatability and linearity of each measuring device were also evaluated. Examples will be given.

The paper also illustrates how this multiphase flowmeter technology improved the diagnosis of the actual well response.
An Improved Method of Slickline Perforating
Authors: King James , Beagrie Bob , Billingham Mathew
Published: December 2007

The BP North Sea Southern Business Unit has successfully incorporated the Schlumberger eFire* electronic firing head system with conventional slickline equipment and perforating guns during a recent trial. Significant benefits were achieved with this system by completing runs quickly and eliminating time-consuming and costly ‘parameter' runs by using conventional memory tools for correlation.

The conventional tools were run within an empty perforating gun housing. During this run the wire was ‘flagged’ at the desired depth and a pass was logged. When logging tools were retrieved and their measurements downloaded, a ‘Tie in Log’ was produced. This was used to correlate the flag on the wire to the ‘Reference Log’. Then 2 7/8-in. HSD* High Shot Density PowerJet* perforating guns were run in hole to the predetermined ‘flag’ depth, and a firing command was sent to the eFire device.

The eFire-Slickline system is an electronic firing head developed for slickline deployment. It is operated by a coded sequence of tension pulses on the slickline wire, which is converted to pressure pulses by a strain sensor in the tool. Following perforating, a ‘disarm’ command is sent and the perforating guns are then pulled out of hole.

Correlation had to be proven for this newly developed system, and this was achieved with the use of a 40-arm caliper over the newly reperforated interval. Results showed that the guns had been fired exactly on depth.

With three 40 ft [12 m] perforating runs capable of being shot in depths greater than 10,000 ft [3048 m] in less than 12 hours, the system proved to be extremely efficient.
Hydraulic Workover for Well Repair and Productivity in Sajaa Field, Sharjah, United Arab Emirates
Authors: Pruitt Randal D. , Ralston Benny , Ali Iftikhar , Van Wynsberghe Dan , Sabine Cedric
Published: December 2007

This is the second half in a two part series on the Sharjah Sajaa gas field repairs. The Sajaa gas condensate field is located onshore in the Emirates of Sharjah UAE. It is producing out of the Thamama limestone reservoir between 11,000 (3,350 meters) and 13,000 (3,960 meters) feet true vertical depth. Reservoir pressure is declining thus creating greater demands on the production strings to prevent collapse from overlying sediments. Sajaa field has had a history of collapsed casing on wells Sajaa 33 and 39 (twice in the same well). In order to investigate the cause of collapse and to prevent further collapse a Peer Assist (Group Meeting) was held in Sharjah to discuss the wells histories and develop a plan forward. Paper One will discuss the CWEAR, READ, casing calculations, the decision tree and well selection. This paper will discuss the live well workover program.
Failure Analysis of Seal Lock Plates in Electric Submersible Pumps
Authors: Samanta B. , Al-Balushi K. R. , Siddiqui R. A. , Al-Araimi S. A. , Al-Habsy Abdullah , Armacanqui Samuel , Al-Hajri Said
Published: December 2007

Electric submersible pumps (ESPs) are used in oil production as effective means of artificial lift. All the major componets of an ESP are put in a long and slender housing. Seal section, located between the motor and the pump, consists of a number of chambers. All the chambers, the base and the head of the seal are connected to the ESP housing through threaded joints between the seal guide and the housing. Lock plates are welded to the housing over each threaded connection to provide additional constraint. The paper presents experimental results to examine different configuration options for lock plates on a type of high power ESP seal housing failed during operation. The paper summarizes the results of mechanical and metallurgical tests, mechanical strength and vibration analyses along with appropriate recommendations. This paper brings into focus the importance and necessity of analyzing even relatively simple and minor components like seal lock plates for safe operation of ESPs.
Multiscale Data Integration Using Markov Random Fields and Markov Chain Monte Carlo: A Field Application in the Middle-East
Authors: Malallah Adel , Perez Hector , Datta-Gupta Akhil , Alamoudi Waleed
Published: December 2007

Integrating multi-resolution data sources into high-resolution reservoir models for accurate performance forecasting is an outstanding challenge in reservoir characterization. Well logs, cores, seismic and production data scan different length scales of heterogeneity and have different degrees of precision. Current geostatistical techniques for data integration rely on a stationarity assumption that is often not borne out by field data. Geologic processes can vary abruptly and systematically over the domain of interest. In addition, geostatistical methods require modeling and specification of variograms that can often be difficult to obtain in field situations.

In this paper, we present a case study from the Middle East to demonstrate the feasibility of a hierarchical approach to spatial modeling based on Markov Random Fields (MRF) and multi-resolution algorithms in image analysis. The field is located in Saudi Arabia south of Riyadh and produces hydrocarbons from the Unayzah Formation, a late Permian siliclastic reservoir. Our proposed approach provides an efficient and powerful framework for data integration accounting for the scale and precision of different data types. Unlike their geostatistical counterparts that simultaneously specify distributions across the entire field, the MRF are based on a collection of full conditional distributions that rely on local neighborhood of each element. This critical focus on local specification provides several advantages: (a) MRFs are far more computationally tractable and are ideally suited to simulation-based computation such as MCMC (Markov Chain Monte Carlo) methods, and (b) model extensions to account for non-stationarities, discontinuity and varying spatial properties at various scales of resolution are accessible in the MRF.

We construct fine scale porosity distribution from well and seismic data explicitly accounting for the varying scale and precision of the data types. First, we derive a relationship between the neutron porosity and the seismic amplitudes. Second, we integrate the seismically derived coarse-scale porosity with fine-scale well data to generate a 3-D field-wide porosity distribution using MRF. The field application demonstrates the feasibility of this emerging technology for practical reservoir characterization.
Experience in Developing a Web Base Workflow to Enhance Competency
Authors: Ming Yeow Lei
Published: December 2007

How do one ensure consistent work quality and process in a large organization with multiple projects and a wide range of technical staff with various competencies and experience ? A web base Production Technology workflow was developed to meet the challenge. Production Technology work process was mapped, reviewed, validated, improved and integrated with other subsurface related disciplines in field development i.e. Geophysics, Geology, Petrophysics, Reservoir Engineering, Drilling and Petroleum Economics. The web base workflow was then implemented across the organization. Steps taken in the mapping, review, validation, improvement and integration process, learning points and benefits of developing such a system are discussed in this paper.

The workflow was categorized into issues identification, term of reference, data acquisition, processing, interpretation, model and archive for all disciplines. Knowledge and experiences of all Production Technologists in the organization was compiled and mapped. A high level workflow was first developed. Points of integration with other disciplines were identified. A "drilled down" process was used to detail out each step until the lowest level consisting of guidelines on each work step.

Steps in preparing the workflow consist of: –Preparing a high level work flow–Appointing each engineer to prepare a specific work process covering well completion design, material selection, sand control, well flow modeling, completion fluids, cement evaluation, wellhead & Christmas trees, artificial lift, etc.–A review process to improve the work flow and formulate the best way to put it in a web base format–A validation process with selected projects to ensure all steps are considered and realistic–The web site was implemented across the organization–Encouraging project teams to follow the work process

Learning points includes: –in-house experiences are more important with consultants as facilitator to compile and integrate the process–fitting workflow of different disciplines in the same categories needs flexibility–engineers working on daily business can contribute to corporate initiatives–concentrated and focus workshop sessions speed up the process

Benefits of the web base workflow includes: –a reference point for engineers to perform their job–more efficient mentoring and guidance from experienced engineers to young engineers–a reference point to quality check work and approve Field Development Plan–one point data base to compile work experiences, company standards and previous work reports for reference
Alternative Economic Criteria for Superior Project Analysis
Authors: Schaaf Robert , Hashim Hosnia
Published: December 2007

Economics performed by projected cost per unit analysis will give better insight into the merits of an oil production project than conventional measurements. This alternative economic metric can easily be used to determine if the project meets the objectives of a particular oil company. The proposed method will give pertinent values to see if return on investment, return on capital employed, operating expense, and cash flow goals will be met. As an additional benefit, cost per unit analysis also incorporates all the accounting pseudo charges. The inclusion of all actual and financial impacts will give a clearer picture as to the outcome a project will achieve. The calculations are not dependent upon predicting future oil prices or assigning a time value to money. Conventional economic measurements (net present value (NPV), internal rate of return (IRR), profitability indexes) can be misleading as to the actual benefit the project has for an oil company. They require that you predict oil prices and, in the case of NPV, assign a time value to money. These typical economic measures were designed to compare one project against another. High IRRs for capital investments can be due to initially high oil production and/or high tax regimes that allow for accelerated depreciation. A good NPV is sometimes achieved just by the large size of a project. Examples will be shown how projects with excellent NPVs and IRRs turned into disastrous economic failures despite performing close to prediction. Using the alternative method described in this paper would assist in avoiding costly mistakes and will help achieve the financial goals a company aspires.
Evaluation of a New Opportunity in a Matured Oil Reservoir
Authors: Al-Enezi Hamdah S. , Al-Qattan Raghad A. , Sinha Satyendra P. , Roe Stan E.
Published: December 2007

Matured oil reservoirs may have to be reviewed for unproduced mobile oil that has been compartmentalized by stratigraphy or structure. This paper presents such a case study in which the reservoir is more than 55 years old with no current producing wells within the case study area. A new well recently penetrated this reservoir and the unexpectedly higher oil column triggered this review. The reservoir is characterized by thin sandstone reservoirs with a strong, active aquifer. The workflow included a geological overview of the reservoir architecture and production/completion history of past completions. The detailed geological model was constructed incorporating the cased-hole oil saturations. This led to the building of a non-scaled-up, concurrent, 2-phase, 3D reservoir model for simulation using Frontsim. The fluid flow trend and the drainage pattern were analyzed by simulating the performance of assumed completions and re-completions of all the existing wells that penetrated this reservoir. The review resulted in the identification of a viable completion strategy to deplete the remaining oil trapped in this reservoir.
An Oil Market Without OPEC!
Authors: Zaid Alforgi M.
Published: December 2007

Oil prices rarely reflected those of a free market. The history of the oil industry documents several instances of monopoly and price fixing. In the last decade however, globalization and the ensuing economic policies raised the possibility that the oil market may finally be free from production and price controls. This paper will analyze the oil supply and demand patterns under scenarios of free market and will predict short and long-term price patterns under these conditions.
Scale Mitigation Enhances Safety and Production
Authors: Lewis D. R. , Zainalabedin K. A. , Al-Habib N. S. , Al-Beaiji T. M. , Al-Qahtani A. M. , Nasr-El-Din H. A.
Published: December 2007

Calcium carbonate scale represents a significant safety and operational problem in offshore carbonate fields operated by Saudi Aramco. Scale can form on any surface where the pressure drop is sufficient for the produced fluids to form the scale and unload entrained solids. These solids will deposit on wellhead equipment such as the wellhead surface valves, piping, well tubulars and may plug the perforations.

Well safety is jeopardized by hindering the operation of critical safety valves such as subsurface safety valves (SSSVs) and surface safety valves (SSVs). Further, scale buildup can cause backpressure problems in the tubing as the pipe internal diameter is reduced. Identification of scale in impacted wells requires periodic inspection and repair.

This paper presents Saudi Aramco's experience in eliminating calcium carbonate scale by treating existing scale using HCl acid. Scale mitigation was initially attempted using an encapsulated inhibitor placed in the rat hole of vertical wells. This method had a limited treatment effective life and Saudi Aramco has moved to using inhibitor squeeze treatments. Chemical squeezes places inhibitor (phosphonate-based) directly into the formation of wet oil producers and is now the currently employed method of long-term prevention of scale.

Case studies using both methods of scale mitigation are discussed as well as future plans to improve the effectiveness of these treatments.
Investigation of Asphaltene Precipitation onset Conditions for Kuwaiti Reservoirs
Authors: Gholoum E. F. , Oskui G. P. , Salman M.
Published: December 2007

Asphaltene Onset Pressure (AOP) conditions were measured for Kuwaiti Reservoirs fluid samples at reservoir, wellhead, and well-bore temperatures along with the saturation pressures by performing a series of pressure depletion tests using the mercury-free, variable volume, fully visual JEFRI-PVT system with laser light scattering. Asphaltene Deposition Envelope (ADE) and P-T phase diagram were developed. Asphaltene onset conditions were also investigated using different precipitants with Stock Tank Oil (STO). A number of titration experiments were performed on the STO using different alkanes and CO2. Our investigation has revealed that CO2 is the most effective asphaltene precipitant followed by alkanes (C1 to C7). To investigate the molecular structure of the asphaltene molecule, advanced analytical techniques such as 1H and 13C NMR and IR spectrometers have been utilized. It was concluded that the total number of carbon atoms was 220 of which 120 were associated with aromatic and the rest were aliphatic rings. The number of aromatic and naphthenic rings were estimated to be 42 and 114 rings respectively.
The Development Of Al Khalij - A Complex Carbonate Field, Offshore Qatar
Authors: Marion Dominique , Noman Rashed , Al-Othman Ibrahim J. , Leschi Pierre
Published: December 2007

The Al Khalij field, located offshore Qatar, was discovered in 1991 and put into production in 1997. The field is original in many aspects. It is one of the few carbonate reservoirs with a stratigraphic closure, the oil being trapped in the upper part of a monocline due to a lateral variation in reservoir facies. In addition, the reservoir lies within the capillary transition zone and consists of a succession of highly conductive oil bearing layers ("drains") in between matrix layers of poor permeability.

Due to the complex reservoir architecture and the large uncertainties in the reservoir dynamic behavior, the field has been developed in several stages to improve understanding and minimize risks.

This paper will discuss on the development of Al Khalij field and will illustrate how advanced technological solutions were applied to overcome complex geological and reservoir problems in order to enhance reservoir performance and well productivity. More specifically the paper will illustrate how: ➢High-resolution 3D seismic has revealed additional areas for development, which were previously considered to be uneconomic.➢Innovative well design in a stair-step manner was implemented to intersect productive layers and increase drainage efficiency with a limited number of wells.➢Stimulation and completion techniques were adapted to optimize productivity while limiting water production.➢Water injection was implemented in the field after validation of its effectiveness through pilot water injection, including tracer test, and through reservoir simulation studies.
Whole Core Analysis - Experience and Challenges
Authors: Honarpour M. M. , Djabbarah N. F. , Sampath K.
Published: December 2007

Whole core analysis is critical for characterizing porosity and directional permeability in heterogeneous, fractured, and/ or anisotropic rocks. Whole core measurements are essential for heterogeneous reservoirs because small-scale heterogeneity may not be appropriately represented in plug measurements. For characterization of multi-phase flow properties (special core analysis) in heterogeneous rocks, whole core analysis is also required.

Few commercial laboratories are equipped to conduct routine measurements on whole cores up to 5 inch in diameter and up to 8 inches long, and importantly, under simulated reservoir net confining stress (NCS). Special whole core analyses are rarely conducted because of difficulties associated with establishing a representative water saturation in drainage capillary pressure experiments and measuring directional effective permeability. Electrical properties are also measured occasionally to determine saturation exponents for situations where resistivity tools are utilized in horizontal or highly deviated wells.

In this paper we provide an overview of routine and special core analysis measurements on whole cores. Results from selected heterogeneous sandstone and carbonate rocks will be discussed. We will also show how the results relate to data obtained from plug analysis at the same depth, with particular emphasis on directional absolute permeability, directional effective permeabilities, trapped fluid saturation, and the effect of net confining stress. Finally, we will describe a novel whole core apparatus and provide examples of capabilities of the system.

In this paper, we will present: Recommended techniques for the determination of directional absolute, effective permeability and establishing initial water saturation in whole cores;Improved understanding of the effect of scale (sample size) on the measured properties;Description of a novel whole core apparatus with measurement of fluid saturation distribution using in-situ saturation monitoring.
Robust Reservoir Characterisation of UAE Heterogeneous Carbonate Reservoirs
Authors: Shedid Shedid A. , Almehaideb Reyadh A.
Published: December 2007

This study is conducted to test and evaluate the use of current methods of reservoir characterization, namely the permeability-porosity correlation, the J-function, and the Reservoir Quality Index (RQI) concepts, for reservoir description of heterogeneous carbonate formations. These approaches were compared with a new technique developed in this paper for improved reservoir description of carbonate reservoirs. This technique is called the Characterization Number (CN) technique and it is based upon considering fluid, rock, rock-fluid properties and flow mechanics of oil reservoirs.

To compare these reservoir characterization techniques, measurements of porosity, absolute permeability, oil and water relative permeability and irreducible water saturation for 83 actual core samples extracted from eight different wells for a new oil reservoir in the U.A.E. are obtained. These experimental data are used first to develop a permeability-porosity correlation. Then, the J-function and the RQI concepts along with the newly developed CN approach are applied and evaluated for reservoir description of the UAE carbonate reservoir under investigation. The results show that the Reservoir Quality Index concept is capable of identifying the flow units while the J-function concept is quiet poor. Also, a more refined identification of flow units is obtained by using the newly-developed Characterization Number. This improved description for the Characterization Number approach may be attributed to the consideration of rock/fluid properties of flowing fluid(s) and flow dynamic conditions of its containing formation.
Planning is Critical for Underbalance Applications with Under-experienced Operators
Authors: Divine Ron
Published: December 2007

The benefits of a properly executed Underbalance Operation (UBO) can result in a well of higher quality and value than that of a conventional well, if proper planning and execution is achieved. This paper discusses the importance of detailed planning when undertaking a UBO and the consequences when conducted improperly.

UBO has demonstrated numerous times that:

Higher penetration rates (>2X) can be realized Higher productivity (>2X) can be achieved Higher reserves recovery are achieved

UBO has proven to reduce development costs, on multi-well projects. The timing for this cost reduction depends largely upon:

the well construction staff in charge of the operation the rate of knowledge transfer from the experienced personnel (service technicians) to the operator the utilization of the information by the operator.

The current knowledge base of UBO is miniscule compared to conventional Overbalance Operation (OBO) knowledge. Access to this knowledge base and implementing the value of the knowledge are critical to expansion of the technology and the establishment of credible operating practices. Global industry organizations such as the International Association of Drilling Contractors (IADC), Society of Petroleum Engineers (SPE), and Gas Technology Institute (GTI) have dedicated significant time and resources to promote the exchange of knowledge and develop safe operating practices of UBO. These organizations should be accessed to reduce the learning time for companies considering the use of UBO equipment and services.

The critical keys to achieving the benefits of UBO, are planning and execution. Several real case histories are presented, which demonstrate the impact of critical planning and execution on project cost. Accessing the knowledge base and implementing lessons learned will enable the user to achieve a successful UB Operation.
Innovative Technology Advances Use of Electromagnetic MWD Offshore in Southern North Sea
Authors: Brett Peter , Weisbeck Denis , Graham Robert
Published: December 2007

The underbalanced drilling campaign undertaken by Shell U.K. Exploration and Production (Shell Expro) offshore in the Southern North Sea has been on the cutting edge of UBD technology since its inception in 1997. Electromagnetic (EM) telemetry systems were incapable of performing in the Southern North Sea due to the depth and nature of the formations. However, recent enhancements to the technology have greatly expanded the scope of EM telemetry. The use of this technology has potential for expanding the scope of underbalanced operations possible in the Southern North Sea.

A fundamental advantage of the EM telemetry system is the capability to transmit data independently of wellbore hydraulics. For example, down-hole pressure data can be transmitted to surface during pressure buildup tests and flow tests. Data can also be transmitted during trips, during connections, with pumps on or off, etc. The transmission of data is unaffected by loss of drilling fluid returns, the use of air, air-mist, foam or other multi-phase drilling fluid mediums generally associated with underbalanced drilling practices. The down-hole instrumentation can also be interrogated or reprogrammed at any time by direct communications protocol, which is completely independent of the rig or drilling activity.

A new, innovative twist to enhance the use of EM telemetry involves the use of insulated casing to reduce signal attenuation and further expand the application of the technology where it has been previously out of reach. This paper discusses rationale for the use of EM telemetry in the Southern North Sea basin and the results of a recent successful field trial of the technology.
Design and Operational Considerations to Maintain Underbalanced Conditions with Concentric Casing Injection
Authors: Mykytiw C. G. , Davidson I. A. , Frink P. J.
Published: December 2007

Underbalanced drilling (UBD) has the potential to add value by maximizing productivity and ultimate recovery by reducing formation damage. The benefits of UBD are of course dependent on the ability to maintain underbalanced conditions throughout the entire life of a well, especially during the drilling phase. The ability to maintain underbalanced conditions is complicated because real UBD wells are rarely, if ever, in a "steady-state" condition and are subject to constantly changing or transient flow behavior. Improved understanding of the transient flow behavior will increase the ability of the rigsite engineer to maintain the desired bottomhole pressure and thus minimize potential formation damaging, overbalanced periods. This paper illustrates how detailed transient analysis provides a rigorous engineering basis for selection of the appropriate methods, to maintain optimum downhole conditions by minimizing bottomhole pressure instability.

Methods to mitigate destabilizing transient effects with drill pipe injection are relatively well understood, due to extensive case histories, but less experience is available with concentric casing (CC) injection and thus less is known on options to control pressure instability.

The UbitTS transient flow simulator is used to optimize design and operational parameters to minimize well slugging tendency and pressure instability when the concentric casing injection technique is employed. Reference is made to a generic test well, but the methodology has application to all UBD operations considering CC injection.
An Approach for Characterizing Your Portfolio
Authors: Pinkney Joanne
Published: December 2007

Using portfolio management and optimization techniques to allocate capital and select the best investment opportunities has been the subject of much discussion in recent papers and articles. However, there are still many practical problems associated with successful portfolio management within an organization. One of the biggest challenges is balancing the trade-off between modeling strategic-level issues versus capital allocation at the sub-strategic level. Two approaches are common. One is to take a high-level view and capture your portfolio at the business unit level. This approach enables clear strategic insights but is limited if business units are composed of several different types of assets contributing variously to the portfolio. A second approach is to start from the bottom up, with each project and sub-project captured in detail. This, however, is time-consuming and can produce confusing results, which are difficult to translate to meaningful capital allocation decisions.

This paper describes a third approach: projects were captured at a detail level appropriate to 1) the goals of the organization, 2) project size relative to the portfolio, 3) project range of uncertainty, and 4) the decision-making level for capital allocation. Also, similar projects were grouped together and a "typical" project chosen to represent the group – using surrogates to reflect the group population. The paper discusses the importance of developing an understanding of key portfolio drivers and adequately characterizing the range of diverse investment opportunities before proceeding with data gathering. This has enabled much greater clarity in answering the often-asked question "Did the portfolio like ‘it’?", and has also established thresholds for material portfolio impact for different sizes and types of projects.

A further benefit is identifying the critical economic and financial metrics that drive the company portfolio and feeding these back to the project originators so that they can focus on improving the accuracy of those metrics in the project economics.
An Experimental Investigation of Infiltrating an Immiscible Organic Spill in a Variably Saturated Soil
Authors: Mohammadi Kourosh , Mousavizadeh Mohammad H. , Kahawita Rene
Published: December 2007

The physical processes governing the infiltration and flow of an immiscible organic liquid in a variably saturated porous medium has been investigated with a laboratory experiment. In order to understand the risks posed by landfills or by oil spills; it needs to understand the mechanisms of migration of these contaminants and consequently the soil contamination. The experimental investigation contained two main sets of laboratory tests, some independent tests in order to find the physical characteristics of the soil such as saturated hydraulic conductivity, soil-moisture retention curves, and the dry density; and the second part was the investigating the NAPL flow using n-heptane. The results of the experiment proved that the NAPL moving downward from a coarse-grained material would encounter a higher entry pressure when a finer-grained layer is contacted.
Near Wellbore Stimulation by Acoustic Waves
Authors: Wong Sau-Wai , van der Bas Fred , Groenenboom Jeroen , Zuiderwijk Pedro
Published: December 2007

Reduced well productivity or injectivity is often caused by near-wellbore formation damage due to the interaction of reservoir formation with drilling and completion fluids. The problem can be further compounded by production induced formation damage. A prime example is fines migration and fines plugging of rock pores or gravel packs.

High frequency sonic waves, especially ultrasonic waves have been used in many industrial applications to remove contaminants like dirt, oil, and grease from parts immersed in fluids. An obvious extension of this application is the removal of wellbore impairment by exposing it to high frequency acoustic waves. Although the concept is old, successful large-scale application of acoustic well stimulation is not common.

Greater understanding of the technology's applicability and limitations are essential in order to design effective downhole acoustic tool and guide successful field implementation. To this end, we have embarked on a dedicated project to mature the technology, which includes dedicated experimentation and tool design. In this paper, we focus on some key experimental results and discuss potential applications in production engineering.
Comprehensive Fracture and Production Analysis Leads to Optimized Fracture Stimulation Strategy in a Laminated Gas/Condensate Reservoir in Oman
Authors: Shaoul Josef R. , de Pater C. J. , Al-Hashmi Mahmoud , Langedijk Robert A.
Published: December 2007

Hydraulic fracturing has been an integral part of the development of two gas/condensate fields in Oman. The producing reservoirs are quite thick (160–190 m) and highly laminated, so fracture height growth and vertical coverage are key issues. High production rates and condensate production also mean that non-Darcy flow in the fracture is important. There are significant variations in permeability and depletion (following several years of production) within the reservoir, which makes any analysis more complicated. There has been an evolution in the fracturing strategy in terms of the number of treatments pumped per well (going from 1 to 5 fractures), the size of proppant used (12/20, 16/30, 20/40) and the size of the pad volume (75 – 350 m3).

Questions existed about the performance of the fracture stimulation treatments, particularly about whether the effectiveness of the fracture stimulations was decreasing over time, as one performance indicator showed. In order to answer these questions, a study was performed to evaluate the individual fracture performance based on the post-frac production logging data (PLT) which gave a production rate for each fracture in the well.
Monitoring Fracturing Fluid Flowback and Optimizing Fracturing Fluid Cleanup Using Chemical Frac Tracers
Authors: Woodroof Robert A. , Asadi Mahmoud , Warren Mark N.
Published: December 2007

Proper fluid and proppant placement are crucial to successful propped fracture stimulation. Numerous completion diagnostic technologies are available to characterize the placement of the treatment. Until recently, characterization of fracturing fluid cleanup could only be simulated in the laboratory and anecdotally monitored in the field. A technique utilizing a family of unique, environmentally friendly, fracturing fluid compatible, chemical tracers has now been developed for quantifying segment-by-segment recovery for individual fracturing treatments and stage-by-stage recovery for multi-stage fracturing treatments. Case histories demonstrate that individual, chemically-differentiated and/or proppant-differentiated, fracturing treatment segments and/or individual fracturing treatment stages are often not being effectively recovered. It has also been demonstrated that the chemical make-up and/or the proppant scheduling of these individual fracturing fluid segments may not only be detrimentally affecting their incremental cleanup but ultimately the production contribution from the corresponding portions of the fractured reservoir. The validation of improvements in fracturing fluid cleanup and production enhancement resulting at least in part from changes in the chemistry of the fracturing fluids and/or changes in proppant scheduling are demonstrated using the tracer technology.
Polymer Fluid-Loss Agent Aids Well Cleanouts
Authors: Rosato M. J. , Supriyono A.
Published: December 2007

Low-permeability gas sands are often cased, perforated, and hydraulically fractured in stages. Commingled production is common, and coiled tubing (CT) has become the prevalent medium for communicating multiple productive intervals between fracture stages and for use as a remedial workover method.

High differential pressures in the wellbore complicate CT intervention considerably. Fluid and solid bridging agents are sometimes used to combat fluid losses and associated well control problems. Calcium carbonate may be the most common bridging agent because it is inexpensive and easy to mix; however, removing the damage caused by calcium carbonate slurries to the formation and proppant packs is difficult and costly. Rock salt is widely used because it causes less formation damage, but it is ineffective against fluid loss. Furthermore, to prevent dissolution of the pill, saturated brine must be used as a workover fluid, increasing costs and contributing to scaling problems.

A unique fluid-loss control agent has been gaining acceptance for temporarily isolating fractured sands. This double derivatized, crosslinkable, hydroxyethyl cellulose (DDHEC) polymer leaves less than 0.5% gel residue by weight, minimizing impact on production. It has demonstrated a regained permeability of 91 to 93% under laboratory conditions and can be completely removed by acid. The polymer has been used in conjunction with 1.25- and 1.75-in. CT with a high degree of success. It does not require expensive brines, is resistant to solvents, and can be used with foam.1,2

The polymer has been applied in eight coiled tubing operations in south Texas, none of which has negatively affected production. This paper provides case histories for several of these field applications.
Sand Management: A Review of Approaches and Concerns
Authors: Mathis Stephen P.
Published: December 2007

As operating conditions become more severe, and the costs associated with well failure escalate, the need for effective sand control increases. However, in a time of tightening economic constraints, the need to control costs also drives decision making. In this time of apparently conflicting concerns, the industry has responded with a move away from traditional Sand Control to what can be more properly termed Sand Management.

Several projects described in the literature are concerned with a particular aspect of Sand Management. Whether it is a description of predictive modeling, preventing sand production through rate control and/or selective perforating, improved sand control through advanced completion practices of frac-pack or horizontal well gravel packing, or the latest in expandable screen products, these studies have focused on one (or perhaps two) aspects of an overall Sand Management project.

To fully grasp the benefit of this new completion paradigm, we must stop looking at well design with a preconceived answer in mind. Rather, all aspects of Sand Management must be considered when making field development decisions. It is the goal of this paper to bring the best from previous studies together to provide a solid review of available Sand Management techniques. However, since all decisions have either positive or negative consequences, this paper also reviews the economic and operational concerns associated with these decisions. An understanding of how initial decisions may impact future options will assist in enhancing our ability to optimize completion type selection.
A Mechanistic Model for Horizontal Gravel Pack Displacement
Authors: Martins A. L. , de Magalhães J. V. M. , Calderon A. , Chagas C. M.
Published: December 2007

This article presents the detailed formulation for each of the three steps of a horizontal gravel pack displacement operation, including sand injection and alpha/beta waves propagation. The main core of the model, aiming the definition of alpha wave height, is based on a well known two layer model. Initially developed for hydrotransport applications, this kind of model has been adapted by several authors for drilled cuttings transport analysis. Besides, a comparison between theoretical predictions and pumping charts from a field operation performed in Campos Basin is presented.
The Impact of Hidden Emulsions on Oil Producing Wells - Stimulation Concept and Field Results
Authors: Espinoza R. , Kleinitz W.
Published: December 2007

Ninety-eight per cent of the total cumulative production from the Cabimas Field has originated from Miocene reservoirs. The difference in density between Miocene oil and water is very small. In addition, this crude oil has a tendency to wet the surfaces of the reservoir rock. Under these conditions, a water- in-oil emulsion, and thus higher viscosities are favoured; this in turn impairs the well production capacity. Three wells were selected (R-A1, R-A2, and R-A3) for the treatment of hidden emulsions with the use of a wetting agent in an organic solvent system.

Another factor that was thought to impair the well production capacity was plugging of the Miocene slotted-liner gravel-packed completions by organic solids which are present. For considering this problem separately, two further wells (R-B1 and R-B2) were treated only with an organic solvent system.

Treatment preparation and pump operation (between 250 and 400 bbl/well) for all five wells were completed in a single week. All of these field operations were simple and were carried out with no operational or safety problems.

Thus, the use of the wetting agent proved to be a successful method for breaking hidden emulsions. Two of the wells treated in this manner, R-A2 and R-A3, respond with an increase in the fluid production rate. An exception was well R- A1; this negative result was due to the existence of a thief zone that fails to receive enough treatment fluid. Wells treated with organic solvents only did not show any change in production rate.
Formation Damage due to Pore Collapse During Pressure Depletion
Authors: Soares A. C. , Altoé J. E. , Bedrikovetsky P. , Ferreira F. H.
Published: December 2007

Pressure depletion during oil production results in increase of overburden effective stress in a porous matrix. This stress in turn causes rock compaction with deformation and consequential permeability and porosity reduction. Production rate decline during oil production due to rock compressibility has been observed in several reservoirs.

The rate decline during pressure depletion is particularly significant for totally unconsolidated or slightly consolidated sandstones, which are typical for Campos Basin reservoirs (Brazil).

Compaction with porosity reduction can improve production by squeezing oil from rock into wellbore. However, compaction can also impair permeability and reduce production. Understanding the interplay of these effects is essential for optimising well placement, for predicting of production rates and for reservoir management.

The collective effects of compaction phenomena on oil production and reservoir behaviour can be understood by means of mathematical experiments using synthetic, laboratory and field data. Mathematical modelling can do reliable prediction of oil production.

A mathematical model for radial oil flow towards wells in a deformable porous media is derived, and the boundary problem for the quasi steady state depletion processes is formulated. The solution is expressed by explicit analytical formulae. The model was applied to the reservoir R (Basin C, Brazil) and results were compared with laboratory data.
Structured Approach To Matrix Stimulation Proves Successful In Oman
Authors: Stevenson Eddie , Avadhut Raiturkar , Al-Harthy Khalfan , Abdulkadir Ramzi , Buijse Marten
Published: December 2007

In early 2000 the success rate for matrix stimulations matched the industry average of around 30%. In mid-2000 an integrated approach was launched, covering all aspects of the stimulation process, and today the success rate for engineered stimulations stands at 85%. This successful approach has been maintained over the past two years and enables new technology to be effectively introduced into the process and opens up additional opportunities. Long term sustained gains have been achieved allowing stimulations to become an effective tool for reservoir management. Examples of successful applications are included below.
Viscoelastic Surfactant Based Self-Diverting Acid for Enhanced Stimulation in Carbonate Reservoirs
Authors: Taylor Deidre , Kumar P. Santhana , Fu Diankui , Jemmali Mohamed , Helou Husam , Chang Frank , Davies Steve , Al-Mutawa Majdi
Published: December 2007

An improved viscoelastic surfactant (VES) based self- diverting acid system has been developed for matrix treatment of carbonate formations. The self-diverting acid contains a novel viscoelastic surfactant that undergoes an increase in viscosity as the fluid penetrates carbonate formations. The decrease in acid concentration as the acid reacts with the carbonate rocks promotes the transformation of spherical micellar structure into a worm-like structure that imparts high viscosity to the fluid. The highly viscous fluid acts as a temporary barrier to reduce further fluid loss into the wormholes and allows complete stimulation of all treating zones. After acid treatment, the viscous fluid is broken by either formation hydrocarbons or pre-flush fluids. The VES based self-diverting acid contains no solids, so there is no bridging when it is pumped through tubing. Rheological studies showed that the acid rapidly developed viscosity as the acid was spent with CaCO3, and the spent fluid was stable up to 300oF. Diversion tests using multiple-core flood equipment showed effective wormholing in both high permeability and low permeability cores. The effectiveness of the new system in diversion and stimulation was confirmed in more than 70 field applications, both through increased well production and/or injection and production logs.