bluuebunny/crossref_metadata_2025 huggingface dataset:
Production Logging In Horizontal Gravel-Packed Highly Viscous Oil Producers in the North Sea
Authors: Riley Steve , Clark Jim , Guivarch Benoit , Chace David , Trcka Daryl
Published: December 2007

Horizontal wells in ChevronTexaco's Captain Field in the North Sea typically exhibit low temperature and pressure in the produced intervals with highly viscous heavy oil production in 2 and 3-phase flow. The highly viscous oil (88 to 135 cp) has historically presented difficult conditions for most horizontal production logging instrumentation due to the tendency for plugging and coating of sensors. The wells are also screened completions which makes logging and interpretation more complex.

Production profiles in three of the Captain Field screened horizontal wells were recently determined utilising an advanced horizontal production logging system. The system combines 2-dimensional parallel-plate capacitance array measurements of 3-phase holdup and velocity profiles, pulsed neutron measurements of 3-phase holdup and water velocity, and conventional production logging measurements to determine the production profile.

This paper presents the results of the logging campaign, including several interesting observations relating to production and measurement in the profiles under flowing conditions (and shut-in, with cross-flow). Atypical velocity profiles due to the presence of heavy, highly-viscous oil. Observation of annular flow regime, or "core flow", where oil flow is surrounded by an annular layer of water. Effects due to flow through the gravel pack and the need for both capacitance and pulsed neutron measurements. The importance of simultaneous measurement of holdups and velocities across-the-wellbore for accurate flow rate determination.
Better Flow Profiling Against Producing Zones Using a New Production Log Interpretation Technique
Authors: Mishra V. K. , Kenawy A. F. , Rutt T. , Ezzat A.
Published: December 2007

All software that is designed to interpret production logs uses the same technique when it comes to dealing with flow across a perforation. This technique involves creating "stable" zones above and below the designated interval, and the flow calculations are done at these "stable" zones, and thus implying that the flow from the interval is equally distributed along its length.

In some cases, it becomes of extreme importance to determine which parts of the perforated interval is actually producing, and producing what. This case arises when some perforating intervals are covering more than one type of rock, or different textures of the same formation.

In this paper, we will show two methods that will define the location and type of flow from every foot of a perforated interval.

A real case is introduced in this paper; the production logs involved are interpreted in the conventional manner, and also with the new techniques. The results show that with the new technique, a clear definition of the contribution of each foot of the perforated interval is shown, and an accurate assessment of the stimulation job performed in the well was achieved.
The Definitive Identification of Candidate Wells for Refracturing
Authors: Oberwinkler Christian , Economides Michael J.
Published: December 2007

While hydraulic fracturing is perhaps the most widely used well completion technique for production or injection enhancement, often treatments are badly or inadequately designed and/or executed. Because fracture treatments are performed in fields which contain hundreds of wells, large databases are generated de facto. These databases contain considerable and valuable information, but they are rarely used by engineers for the purpose of improving or optimizing future treatments or to select the most promising refracturing candidates. There are two main reasons, which prevent such obvious use: lack of time and, especially, lack of appropriate tools.

There are, however, emerging methodologies, which can be applied for this exercise and they fall under the general category of Data Mining and Knowledge Discovery. Although these terms are already established, the specific tool used in the method and case study presented in this paper is new and innovative.

The method uses Self-Organizing Maps (SOMs) which are used to group (cluster) high-dimensional data. Clustering data can be done with multidimensional cross plots to a certain extent, but when a large amount of parameters (dimensions) is necessary, the cross plot loses its effectiveness and coherence.

The technique, as shown also in the case study of this paper, first identifies underperforming wells in relation to others in a given field. SOMs have been employed in this work to cluster different fracture input parameters (proppant volume, fluid volume, net pay thickness, etc.) of about 200 fracture treatments into different groups. To differentiate between these groups, the incremental post-fracture treatment production has been used as an output. The comparison of the different clusters with the corresponding output reveals a better practice for future treatments and possible refracture candidates. It is important to note that the output has not been included in the clustering process itself.

Once the wells are identified, a Neural Network is trained to rank the most promising wells for a refracture treatment and new optimum fracture designs are prepared which compare ideal performance with the one observed. These are then the criterion for deciding refracturing candidates as well as a significant aid in the design of treatments in new wells in the neighborhood.

This work and the methodology that it implies provide for a faster and more efficient way to analyze well performance data and, thus, to reach a verdict on the success or failure of past treatments. The technique leads to the definitive selection of refracturing candidates and to the improvement of future designs.

(Note: for better understanding this paper should be viewed and copied in color)
Case Study: Analyzing Bottomhole Temperature Gauge Data in Gulf of Mexico Frac Packs to Optimize Fracture Fluid Crosslink, Stability and Break Times
Authors: Malochee S. , Comeaux B.
Published: December 2007

The crosslinkers, buffers and breakers that are used in fracture fluid designs have typically been tested with emphasis placed on break time. Fracture fluids for high permeability formations need to be designed for multiple purposes: wellbore crosslink time, stability, and break time. Crosslink time in the wellbore is critical for fracture propagation. Stability is critical for proppant transport. Break time is critical for proper cleanup of the fracture fluid so that proppant-pack conductivity is maximized. It is important that these times are based on the correct temperatures.

Fracture fluid additives have primarily been based on bottomhole static temperature (BHST) or some portion of BHST. The wellbore temperature while pumping is typically cooler than BHST. Crosslink and stability time should be based on the cooler wellbore temperature. Test temperature for break time, on the other hand, should be based on temperature in the fracture once the treatment has been completed. Therefore, a fluid design needs to effectively satisfy: 1) crosslink time at a cooler wellbore temperature while pumping, 2) stability time at a cooler wellbore and in-situ fracture temperature while pumping, and 3) break time at a temperature closer to bottomhole static temperature once pumping has ceased.

This paper analyzes the bottomhole gauge data from over 50 frac packs in the Gulf of Mexico. The data was evaluated by identifying the maximum cool down while pumping and identifying the percentage of temperature increase after treatment. The BHST's ranged from 122°F to 262°F. The objective is to evaluate the design temperature so that the recommended fracture fluid will have an effective crosslink in the cooled-down workstring, stability for proppant transport, and an effective break time upon completion of the fracture treatment.
Coupling of a Surface Network With Reservoir Simulation
Authors: Kosmala Alexandre , Aanonsen Sigurd Ivar , Gajraj Allyson , Biran Valerie , Brusdal Kari , Stokkenes Arild , Torrens Richard
Published: December 2007

A controller providing a link between reservoir and network simulators has been developed to facilitate reservoir and production management. An optimizer included in the network simulator ensures that optimal management of the coupled system is achieved. The utility of the tool is first tested using a very simple reservoir model with one injector and a single smart producer, and subsequently demonstrated for water-alternating-gas (WAG) injection in two North Sea field cases. For the synthetic test case, various optimization scenarios are explored with the coupled system and compared to standalone flow simulation results. In the North Sea Field 1, optimum oil production is achieved by adjusting the settings of the surface valves as well as the downhole intelligent completion valves (ICVs); in Field 2, gas lift is optimized over time. The coupled system has given more accurate and realistic results in all cases. For the synthetic test case, the coupling gives a significantly higher production than the standalone reservoir simulator run whatever the optimization scenario. For the Field 1 smart well case, the coupled results match historic performance more closely because the pressure drop across the flow lines and surface facilities, the interaction among the wells in the production network, and the boundary conditions are all accounted for. For the gas lift optimization case, the coupled system gives more realistic results with respect to the potential for increased oil production and recovery than the standalone reservoir and network models.
Intelligent Distributed Management System for Automated Wells (SGPA): Experience and Results
Authors: Correa Jose F. , Lepkison Herman , Bittencourt Antonio C.
Published: December 2007

SGPA is an Intelligent Distributed Management System for Automated Wells developed back in 2001/2002 for sucker-rod pumped wells analysis and management. The SGPA concepts and ideas were presented in the 2002 SPE ATC&E, in San Antonio, Tx.

SGPA operates under three main subsystems, Data consistency module for acquisition and consistency of the information from different sources, Knowledge module for well analysis based on Artificial Lift experts coded experience and dynamometer card apprenticeship module for dynamometer card patterns development.

The sucker rod pumping experts knowledge were coded, used and improved in several well analysis creating a Sucker rod pumping knowledge base used now to do more precise analysis and also to teach and train new engineers. Well automation brought a big change to the field personnel routine, in a few months a huge amount of well information became available and the field personnel urged to use it to implement well analysis.

The dynamometer card patterns to be used by the PLC at the well site for optimization and control was also an issue. The use of patterns for normal operation, pump-off, gas lock, etc… is a key feature of the well automation system and a fundamental necessity in any well analysis. The SGPA dynamometer card apprenticeship subsystem was used to develop dynamometer patterns based in the acquired real dynamometric cards stored in the well automation system databases.

This paper presents an in depth description of the SGPA knowledge base after one year use and the set of dynamometric card patterns developed.
Options for Exploiting Stranded Gas – An Overview of Issues, Opportunities & Solutions
Authors: Verghese Joe T
Published: December 2007

A significant proportion of the growth gas reserves seen in recent years is stranded gas, that is gas which is remote from markets and often in hostile environments.

Simultaneously, there is a decisive trend in the utilization of gas relative to other fossil fuels. Natural gas has been steadily winning market share from coal, and is currently overtaking coal in usage worldwide.

The above trends have spawned the development and commercialization of a range of technologies that are directed at monetizing stranded gas reserves. These technologies offer the promise of economically linking these remote gas assets to profitable markets.

This paper will overview optional routes available for stranded gas utilization and its transportation to viable markets, and comment on the maturity and commercialization status of the underlying technologies.

It is hoped that this analysis will provide some insight into the potential these available/emerging technologies (for example, niche LNG, GTL, CNG) can offer in providing robust solutions to the economic exploitation of stranded gas.
Hydrates for Transport of Stranded Natural Gas
Authors: Berner Dale
Published: December 2007

This paper addresses the feasibility of using a Natural Gas Hydrate, NGH, transport-system to economically convey remote, stranded, and/or associated natural gas to market. Such a transport system could convey NGH either on retrofitted crude oil carriers, carrying both NGH and oil, or on new custom-built carrier designed specifically for NGH.
Design Considerations for an LNG Receiving Terminal
Authors: Kaplan Al , Yang C. C.
Published: December 2007

LNG receiving or import terminals are not a new phenomenon, with over 40 in existence worldwide, the oldest being more than 30 years old. At present, there is renewed interest in LNG receiving terminals outside Japan, due to the increased demand for clean burning energy and an abundance of natural gas worldwide. Currently, there are at least 50 proposed new receiving terminals in various stages worldwide; more than 35 potential projects have been identified for the North American market alone. This paper will address the key drivers governing LNG receiving facility design and will then examine key design issues for each of the main elements os such terminals. This paper primarily addresses the issues surrounding onshore terminals, but also in specific areas highlights the differences between an onshore and offshore facility.
The Role of Geomechanical Earth Modeling in the Unconsolidated Pre-Khuff Field Completion Design for Saudi Arabian Gas Wells
Authors: Zillur Rahim , Al-Qahtani Mohammed Y. , Bartko Kirk M. , Goodman Harvey , Hilarides W. K. , Norman W. D.
Published: December 2007

Geomechanical modeling is playing an increasingly important role at Saudi Aramco during the earliest phases of field development planning. Field development decisions are aided by an accurate assessment of well design options that are closely tied to the existing geological and engineering data set using geomechanics technology.

Beginning at the reservoir, completion design in highly productive mechanically weak sandstone formations, and stronger – less productive formation intervals that must be fracture stimulated to produce, depend heavily on the accuracy of the Pre-Khuff geomechanical model that recognizes the complexity of this geological environment.1

The Pre-Khuff model finds formation layer stress and rock strength to be to extremely anisotropic, with stress magnitude and horizontal stress differences linked closely to formation layer stiffness, namely, static Young's modulus. The impact of interval stress and strength complexities to sanding potential, frac-pack design in sand-prone intervals, and hydraulic fracture stimulation design in stronger sanding-free intervals, is modeled using commercially available petrophysics and fracture stimulation design software. Perforation stability is modeled by customized and calibrated numerical modules developed by Saudi Aramco specialists and ChevronTexaco's Rock Mechanics Analysis group.

An overview of the Pre-Khuff geomechanical earth model is presented in the paper. Perforation stability forecasts, including the impact on perforation design and completion type selection is also presented with field performance results. Calibration to the geomechanical model for various fields and reservoir conditions are also illustrated.
Streamlining the WorkFlow from Structure Model to Reservoir Grid
Authors: Hoffman K. S. , Neave J. W. , Klein R. T.
Published: December 2007

Reservoir grid models and geologic structure models are often two distinct and unrelated entities. Ideally, these two models would be identical; realistically, however, geologic modeling systems often do not produce high quality reservoir grids, and gridding systems fall short of producing good geologic models. The problem is often one of resolution and the approach taken for fault modeling. When the reservoir grid is designed first, the fault framework and geologic layering is often approximated, and the model is not optimally compartmentalized. Antithetic faults are often a problem in this case. Moreover, geologic models created in one application often need to be transferred to another application for reservoir gridding, resulting in loss of resolution.

We have developed a new method for creating a 3D reservoir grid from a high-quality geologic structure model. Here, the geologic model is a fault block-oriented, compartmentalized model which has been created using a unique algorithm for producing internally consistent stratigraphic layers. The fault reconstruction process used in this algorithm conserves volume and produces a water-tight, compartmentalized geologic model, which may include normal faults, antithetic faults (also known as "y" or lambda faults), growth faults, reverse or thrust faults, and multi-valued surfaces such as overturned folds or salt domes.

When the reservoir grid is based on this type of internally consistent geologic model, the geologic structure defines the reservoir grid, rather than the grid defining the structure. All types of faults are easily transferred from the geologic model to the reservoir model. Individual faults may be selected for the alignment of the reservoir grid in the I, J or IJ direction; the grid may even conform to a multi-valued surface.

The process of transferring the geologic model to a reservoir grid is extremely fast – usually requiring just minutes to grid models even with large numbers of faults. The speed, simplicity of transfer (without loss of geologic definition), and quality of the final product allows the asset team to work together to refine the reservoir grid while maintaining detailed geologic input.
Is Ottawa Still Evolving? API Specifications and Conductivity in 2003
Authors: Stephenson Chris J. , Rickards Allan R. , Brannon Harold D.
Published: December 2007

Proppant mesh size is arguably the most important characteristic for controlling and describing the quality of a particular propping material. More importantly the mesh size relates to the permeability performance of the proppant. For many years now, a series of American Petroleum Institute Recommended Practices have existed for testing the quality of the numerous proppants available. Along with testing procedures, these documents contain suggested typical proppant sizes, such as 20/40 mesh, and the size specifications they should meet both at the source and at the point of application. In addition to other size criteria, it has long been accepted that if a batch of proppant has at least 90% of its mass between the designating mesh sizes, it passes an acceptable quality control target. However, it is possible to have two samples of 20/40 proppant that are both 90% in-size but could, for example, have a two-fold difference in permeability due to differences in distribution. In this case would the median diameter be a more informative description of the proppant size?

With conductivity as the final goal, does the mesh size have much relevance other than as a guide to performance? In many reservoirs, the success of a fracturing treatment often depends upon a sufficient permeability contrast between the fractured formation(s) and the proppant placed. However, other factors that influence the fracture conductivity, such as polymer damage, multiphase flow and non-Darcy effects, can greatly reduce the significance of the baseline permeability. For some reservoirs, operators consider proppant size to be extremely important to the overall success of a fracturing treatment and demand tight quality control at the wellsite. In contrast, there are reservoirs where operators can pump non-typical proppant sizes or even those that do not meet API specifications. Also, in recent years the industry has seen the introduction and acceptance of several products that are not typically sized, such as 14/30 mesh deformable proppants for flowback control and, most recently, a broad-mesh, intermediate-strength proppant. So are industry attitudes changing and becoming more open to new ways of achieving fracturing success?
High Strength, Ultra-Lightweight Proppant Lends New Dimensions to Hydraulic Fracturing Applications
Authors: Rickards Allan R. , Brannon Harold D. , Wood William D. , Stephenson Christopher J.
Published: December 2007

Since the earliest fracturing treatments over 50 years ago, many different materials have been used including sand, glass beads, walnut hulls, and metal shot. Today's commonly used proppants include various sands, resin-coated sands, intermediate strength ceramics, and sintered bauxite, each employed for their ability to cost effectively withstand the respective reservoir closure stress environment. As the relative strength of the various materials increases, so too have the respective particle densities, ranging from 2.65 g/cc for sands to 3.4 g/cc for the sintered bauxite. Unfortunately, increasing particle density leads directly to increasing degree of difficulty with proppant transport and a reduced propped fracture volume for equal amounts of the respective proppant, reducing fracture conductivity. Intuitively, one expects a lesser density proppant would be easier to transport, allowing for reduced demands on the fracturing fluids, and if it had sufficient strength, would provide increased width, hence, enhanced fracture conductivity.

Previous efforts undertaken to employ lower density materials as proppant have generally resulted in failure due to insufficient strength to maintain fracture conductivity at even the lowest of closure stresses (1,000 psi). Recent research on material properties has at last led to the development of an ultra-lightweight material with particle strength more than sufficient for most hydraulic fracturing applications. The current ultra-lightweight proppants have apparent specific gravity's of 1.25 and 1.75 g/cc. Laboratory tests will demonstrate exceptional fracture conductivity at stresses to 8,000 psi. This paper will present data illustrating the performance of the new ultra-lightweight proppant over a broad range of conditions and a discussion of relative performance in field applications.
An Environmentally Friendly, Highly Effective Hydrogen Sulphide Scavenger for Drilling Fluids
Authors: Davidson Eric , Hall John , Temple Colin
Published: December 2007

Drilling into a hydrogen-sulphide (H2S) rich formation presents risks that the highly toxic gas might be carried to the surface and released, thus creating a serious hazard. To mitigate this risk, it is standard practice to run the drilling mud at high pH and to include a sulphide scavenger. Commonly, such scavengers are based on iron oxide or on zinc compounds. Iron oxide has the advantage of being environmentally friendly but, at high pH, has a slow reaction rate. In contrast, the zinc-based scavengers have a faster action. In particular, chelated zinc, which is water soluble, has a very fast reaction rate. The action of the zinc in any form is to precipitate the sulphide as a zinc salt. Precipitation prevents release of hydrogen sulphide gas, but it contaminates the mud and cuttings with zinc. In many parts of the world, disposal of material containing zinc is a problem because it is regarded as a toxic heavy metal. For example, discharge is forbidden in many international waters and cuttings for disposal on land may have to be treated as special waste.

E&P Forum recommends product substitution as a source reduction method of reducing waste disposal problems and associated costs. Accordingly, a less toxic alternative was pursued.

A new scavenger has been developed that relies on the affinity between iron and sulphide. The active chemical is a form of ferrous iron complexed with a carbohydrate derivative. It is highly soluble in the brine phases of water-based mud and will not precipitate at a pH over 12. Because the iron is in solution, the reaction with sulphide is instantaneous and complete. The paper deals with the environmental implications of zinc vs. iron and the development of the new scavenger. The paper will present details of case histories concerning operations on a reservoir containing 25% H2S. Even in these demanding conditions, no H2S was detected at the surface.
All Lost-Circulation Materials and Systems Are Not Created Equal
Authors: Whitfill Donald L. , Hemphill Terry
Published: December 2007

Controlling circulation loss during well construction is more than just selecting the proper type of lost circulation material (LCM).1 A fully engineered approach is recommended. This approach incorporates a number of planning tools, including: Borehole stability analysisHydraulics modeling to estimate equivalent circulating density (ECD)Drilling fluid and LCM material selection to help minimize effects on ECD.

Planning should include means to provide on-site monitoring using pressure while drilling (PWD), and connection flow monitoring and timely application of LCM and treatments.

The following practices are advocated to provide the best available technology: Base the amount of LCM on volume rather than weight.Pretreat with LCM before drilling high risk lost circulation zones.Add subsequent treatments as sweeps, rather than adding into the bulk drilling fluid system in the suction pit.

Results from a new laboratory study on LCM testing are discussed and compared to more classic large scale laboratory data from Drilling Engineering Association (DEA) joint industry experiments conducted in the 1980s.2 Results are discussed that demonstrate a rationale for pretreating drilling fluids with combinations of resilient graphitic carbon (RGC) and sized calcium carbonate (SCC) where a high probability for loss of circulation exists.

Simplified treatments using engineered combinations of LCM in a single sack may be used for different applications, such as drilling depleted sands, seepage losses, and severe lost circulation. In some cases a more specialized treatment may be required, such as a two component system pumped down the drillpipe and annulus simultaneously, forming a flexible seal in the fracture, and effectively isolating the borehole pressure from the fracture tip.
Requirements of Downhole Flow Control Valves
Authors: Gai H.
Published: December 2007

A brief review of Down Hole Flow Control technology shows that it is still far from mature. Efforts on characterizing DHFC valves highlight some fundamental challenges, and indicate that DHFC valves are flow control devices, not pressure control devices as chokes are. The DHFC valve requirements are then detailed, including the functionality, mechanical, and reliability requirements and other considerations, and an attempt is made to dispel some of the misconceptions. Some simple guidelines for system/valve design and selection are also presented, providing a useful tool for the user. An example is given, demonstrating the complexity of the interactions of multiple well and reservoir parameters and some of the design basics, and the use of a simple spreadsheet simulator.

It is concluded that while the DHFC technology has proved itself as viable and capable of delivering huge value to the industry, there remain some serious technical challenges, which call for continued and concerted efforts. The complex requirements should be managed with a system approach not just focusing on discrete components. Analytical tools are needed for proper system design and validation in the given application environment to achieve success.
MC305 Aconcagua SCSSV Control Hydraulics Problems Uncommanded and SCSSV Closure Problems
Authors: Hare Simon , May Dwayne , McCalvin David , Martyniak Paul
Published: December 2007

The Aconcagua field, operated by TotalFinaElf, is located in 7000’ of water in MC305, and is part of the Canyon Express development. Aconcagua is a dry gas field, comprising four subsea wells. The Canyon Express project involves a commingled tieback of three dry gas fields, owned and operated by different companies, through a jointly owned twin 12" flowline tieback to a third party host platform at 56 miles distance.

Two problems have been experienced in the operation of the SCSSVs, initially during the flow-back testing, and later in the production phase. The first problem was the rapid rise in hydraulic pressure in the control lines during well start-up; this is related to a problem with the design of the pod hydraulics, and is found on all four wells in the Aconcagua field. The second problem is related to uncommanded closures of the SCSSV; this problem has been experienced on three out of the four Aconcagua wells, to varying degrees of severity. Although procedural mitigation methods have enabled the MC305-1 and MC305-2 wells to operate correctly, the uncommanded closures have continued in the MC305-4 well during the first four months of field life.

The MC305-4 well is located in 7,055 feet of water; top of reservoir is located at around 12,500 feet TVD below MSL, and the SCSSV is set at 9,400 feet below MSL. The TR SCSSV is a Schlumberger TRC-DH type; it has dual redundant pistons with a gas spring system to counter balance the hydrostatic pressure of the Transaqua HT control fluid (4,300 psi at the SCSSV depth).

This paper describes the hydraulic design of the control pods, the reasons for the increase in hydraulic supply pressures in the control lines, and the procedural steps taken to mitigate over-pressurisation of the SCSSV hydraulics. Also described are the system modes associated with the uncommanded SCSSV closures, and the diagnostic testing carried out to establish the reasons for the closures. The detail of the steps taken to avoid the closures is offered, both with procedural and hardware modifications noted.
Hydrate Prevention and Methanol Distribution on Canyon Express
Authors: Cooley C. , Wallace B. K. , Gudimetla R.
Published: December 2007

The Canyon Express field in deepwater Gulf of Mexico is a development consisting of multiple subsea gas-condensate wells owned by different companies. Each deepwater well (ranging from 6400 to 7250 foot water depth) flows into one of two 57 mile, 12" flowlines which tie the subsea wells to a shallow water host platform on the Continental Shelf. The production from each well is predominantly methane gas but also consists of produced water and condensate. Due to the nature of the production and the combination of high pressures / low temperatures expected, the potential for hydrate formation is a serious concern to system operability. To adequately protect the system against hydrate formation and deposition, injection of hydrate inhibitor (methanol) at each subsea well from a common umbilical system is being employed. Although wet gas metering is being used at each well to measure gas and liquid rate, water content per well cannot be accurately predicted. Thus, a robust methanol injection strategy was required to effectively inhibit hydrate formation. This paper presents the design of the methanol injection system and development of the overall injection strategy. Examples from the early field life of the Canyon Express development will be presented which demonstrate the application of this injection strategy to the system operation.
Simulations of Compositional Gradients in Hydrocarbon Reservoirs under the Influence of a Temperature Gradient
Authors: Pedersen K. S. , Lindeloff N.
Published: December 2007

A model based on irreversible thermodynamics is presented for simulating the compositional variation with depth in petroleum reservoirs with a vertical temperature gradient. By assuming that the system is at a stationary state, and that no heat flux exists in an isothermal reservoir, the influence of a temperature gradient can be expressed in terms of partial molar enthalpies of the present components. Experimental data are presented for the compositional variation with depth in two high-pressure gas condensate reservoirs with a vertical temperature gradient. The observed compositional variations with depth are higher than in an isothermal reservoir and can be modeled quite closely using the proposed model.
SEC Defined Reserves Booking: What the Petrophysicist Needs to Know
Authors: Truman Robert B. , Davidson James A.
Published: December 2007

This paper addresses the petrophysical analysis issues related to the Securities and Exchange Commission definition of proved, proved developed, and proved undeveloped oil and gas reserves. It informs the practicing petrophysicist of the current SEC views concerning the relative merit of the various engineering and geological data typically utilized in reserve booking efforts so that he can be conversant with the important concepts and make the proper recommendations to ensure the appropriate data have been acquired and the applicable analyses performed. Current state of technology is addressed along with issues as they relate to the application of SEC definitions. There are numerous issues related to these definitions including the criteria for reasonable certainty; the weight given to the analysis of open-hole well log data; considerations for what constitutes representative fluid volumes from wireline and other well tests; and the role of core analysis, pilot studies, analogous reservoirs as well as other data sources such as seismic data to establish reservoir continuity. The strengths, limitations and use of these various data sets to establish proved developed reserves are presented along with areas requiring further industry clarification or development.

For example, according to the SEC, "Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test."1 However, in the Gulf of Mexico, reserves are often classified as proved in the absence of production or flow tests when certain criteria are met. This occurs when the case for reasonable certainty is effectively made. In other cases, proved developed reserves such as thin bedded sections may require a flow test, cores and a more complete set of well logs and high resolution borehole information.

Contractual, economic, and regulatory issues will not be addressed, nor will issues relating to drainage areas, recovery factors, enhanced recovery or other engineering-related issues be discussed.
Introduction to Methods to Fracture More Than 30 Zones in a Well-Per-Day and Used on About 1,000 Wells-Per-Year
Authors: Demin Wang , Shijin Pan , Chaoyang Xie , Gang Wang
Published: December 2007

This paper introduces a method to fracture more than 30 zones in a single well per day and also how to fracture low permeability zones when the impermeable barrier(s) to high permeability and high water cut zones are only about 0.5 m thick and not create channels in the cement sheathe.

The above methods are used in a large scale in Daqing Oil Field (about 1,000 wells per year since 1980). The results are quite good, cumulative incremental oil production by these fracturing methods is about 60 million tons; the fracturing costs per ton of incremental oil is about $6.
An Integrated Selective Testing Service for Horizontal Wells
Authors: Al-Sharji H. , Hook P.
Published: December 2007

Horizontal well operators use the interpreted results of tubing-conveyed production logging as a basis for well treatment decisions. However, the complexity of near-horizontal flow regimes and flow behavior of in-field laterals still provide a challenge to log evaluation in terms of both accuracy and time required for interpretation.

This paper presents a field example demonstrating the success of a service that integrates surface and downhole equipment for a simpler alternative to current horizontal production logging techniques. At the surface, a mobile multiphase flowmeter is connected to the well flowline. Two pieces of equipment are conveyed downhole using coiled tubing: a resettable inflate packer configured to plug flow, and a pulsed neutron logging tool contained inside a housing purpose-built to enable packer operation while acquiring log measurements.

The service involves consecutive packer setting at strategic points along the producing well length. Production from the section isolated by the packer is determined by the change in multiphase flowmeter recordings at the surface before and after packer setting. Downhole logging sensors verify packer element seal, and monitor borehole pressure in real time.

By measuring flow at the surface, the service is completely insensitive to the complexity of near-horizontal multiphase flow regimes downhole. Well production instability is immediately observed and countered by extending the recording time during packer setting. The accuracy of the resultant flow profile is not degraded by downhole gas, not open to interpretation, and more reflective of well remediation results involving zonal shutoff.

Because multiphase production along the length of the lateral is accurately evaluated in real time, the service offers an efficient, cost-effective alternative to horizontal production logging. Following this diagnostic evaluation, well operators are now in a position to treat laterals using the coiled tubing unit already in operation at the wellsite.
A Combined Diagnosis and Treatment Service for Multilateral Injector Wells
Authors: Al Farsi N. , Ojulari B. , Hook P. , Staal T. W.
Published: December 2007

Patterns for multilateral (ML) injector and producer wells are successful in boosting reservoir oil recovery, but waterflood sweep uniformity is critical in this environment. Until recently, complete quantitative evaluation of injection water distribution in ML legs has only been possible by whipstocking workover pipe into each lateral leg, and by subsequent log sensor pumpdown operations. Any well remediation operation was conducted separately from the logging operation. The complexities and costs of evaluating and treating MLs have left well operators with limited practical and economical options for remediation.

The last 10 years have seen successful equipment development for selectively entering level 1 and 2 lateral extensions—classifications of the Technical Advancement of ML wells (TAML) (Fig. 1)—with coiled tubing (CT). This paper describes a new, combined diagnosis and treatment service enabled by conveying logging sensors into any selected leg of a ML well. Initially, the relative injection distribution between legs is measured by pulsed neutron logging the injection-water velocity along the well's natural path. Then a real-time decision is made as to which legs to enter for further evaluating the water-injection profile. Evaluation results are available in real time for planning treatments to improve waterflood sweep efficiency. The CT unit, using the same lateral reentry equipment as for log sensor conveyance, can then do stimulation or water shutoff treatments. If desired, the ML can undergo post-treatment evaluative logging.

ML injector diagnosis and treatment are now possible with a single combined operation at the wellsite, without a workover or drilling rig.

The ability to simultaneously access and log all levels of live ML wells with CT, for real-time decisions and action on optimal treatment, provides a cost-effective option for optimizing recovery.
Perforating System Selection for Optimum Well Inflow Performance, Alba Field, Equatorial Guinea
Authors: Snider Phil , Rindels Chuck , Folse Kent , Hardesty John , Clark Nathan
Published: December 2007

An ever-expanding range of reservoir scenarios continues to challenge oilfield operators and service companies to provide completions that will not only produce at optimum levels but will also accelerate return on investment (ROI). Unfortunately, in attempting to satisfy these needs, developers often overlook a very important component of the completion scenario — the perforation process. This paper will demonstrate that focusing perforator system performance on reservoir productivity rather than on the shaped charge, performance optimized for concrete testing (which is the case with API Section I) can ultimately lead to significant improvement in well inflow performance. The discussion will demonstrate that:

The actual performance of given shaped charges at in-situ conditions for both penetration and effective flow should be evaluated to make perforating decisions for the completion process. Applying the perforating concepts discussed in this paper significantly optimized well productivity for a major West Africa project in which wells with 1000 feet of perforations were to be completed.

Economic penetration studies, perforation performance evaluation, optimization using a Perforation Flow Laboratory, and tests on the Alba-Field core samples were conducted using unique strategies.

An innovative live-well modular gun system was utilized on this project to maximize well inflow performance.

The system will provide significant cost savings to the operator and will generate much improved well productivity over that which had been attained in the exploration well program.
A New Thermal Insulating Fluid and Its Application in Deepwater Riser Insulation in the Gulf of Mexico
Authors: Wang Xiaolan , Javora Paul , Qu Qi , Pearcy Rick , Starliper Art
Published: December 2007

Undesired heat loss from the production tubing, or uncontrolled heat transfer to outer annuli contributes to the formation of gas hydrates and causes the deposition of paraffin and asphaltene materials to reduce the production rate. The successful application of thermal insulating fluids in the last several years has demonstrated that such fluids can effectively control the heat loss. In some cases, heat loss from the produced fluids due to conduction and convection can be reduced by more than 90% when compared to traditional packer fluids.

Recently, a new thermal insulating fluid system with superior thermal properties has been developed. Compared to the current existing insulation fluids, the new insulating fluid system provides high viscosity at low shear rate range to reduce fluid convection rate. And it also provides lower viscosity at high shear rate range to facilitate the fluid placement. The new fluid with improved insulation properties has proven to be an attractive alternative to the current insulation method for deepwater risers. This paper highlights the development of this new thermal insulating fluid and its application in deepwater riser insulation in the Gulf of Mexico. Laboratory data and field cases are also presented to demonstrate the effectiveness of this fluid system.
Learning Along the Way: Mahogany Field in Trinidad After 5 Years, 700 Bscf, 22 MMbo and No Lost Time Incidents
Authors: Mackow H. M. , Bally Y. K. , Perry J. T. , Lachance D. P.
Published: December 2007

On November 07, 2002 the Mahogany Field in Trinidad passed five years since operations started, and the field continues to have a great record in safety, production and drilling. The field has had no DAFWC (Days Away From Work Cases) since operations started in 1997, and that has also included 2 major phases of drilling on both platforms Mahogany A and Mahogany B. Cumulative production to date is 0.7 Tscf of gas and 22 MMbo.

In August 2002, the Mahogany Field produced over 30,000 STBOPD, while in May 2001 (before the current drilling phase started) the production was 12,200 STBOPD. This production story is another remarkable milestone for the field. Apart from being the largest combined gas and oil producing field in bp Trinidad and Tobago LLC (currently 479 mmscfd and 38,000 STBOPD – October 2002) the field now produces more hydrocarbon liquids than any other field in Trinidad and Tobago. This paper reflects on how and why the field was developed, shares some of the technologies employed and highlights the challenges and successes that the teams have faced in developing the field.
Virtual File Room – Storage and Retrieval of Electronic Documents
Authors: Liddell Bill , Ternyik Joe , Modi Rupam
Published: December 2007

Data and information must transcend into knowledge for greater engineering efficiency. One of the barriers is the age-old problem of the management of well and field-related data files generated by the engineering community.

A key issue confronting the engineering staff is where to store these unstructured data files. Most engineers store them on their personal computer hard drives or on restricted network drives where only that engineer can use them. It becomes increasingly difficult for the engineering community to find vital data and information, which often leads to recreating existing work. Recent implementations of document management systems seem to handle scanned images quite well, but have failed to incorporate data files.1 To solve this problem, an operating-system-independent solution has been developed that allows for data sharing between groups.

This paper will review the steps taken to standardize the data storage process. A method for obtaining an agreed upon taxonomy will be discussed. In order for this new system to be easy for the engineer to use, a web-based application, using J2EE standards, was developed. This tool allows the engineer to quickly identify key attributes of a data file and upload the file to a network server. The deployment and use of this tool will be shown.

Retrieval of the stored information is also extremely important. There will be a review of using the web-based solution to access these data files. In addition, once the documents have been properly organized, many tools can now be used to visualize this information and quickly assess well data and performance.
Knowledge Management: Ensuring Success
Authors: Smith David , DeHart Rory , Smith Ken
Published: December 2007

A growing number of publications focus on Knowledge Management (KM) programs, but to date very little has been written about what those programs can do to ensure their success. Not all implementations are flawless. As a result, developing the right knowledge management measurement model can be the most critical component in the ongoing viability of any KM initiative. The right measures can quickly indicate the health of a knowledge management program and provide insight into opportunities for enhancement.

A KM program for Perforating was initiated due to a compelling business need. The program design included a measurement model that adopted recognized business metrics and indicators, as well as daily KM activity measures to gauge the health, growth, and reach of the community.

With early and consistent monitoring, this balanced model for measurement allowed the quick identification of several key opportunities. Expansion and enrichment of the KM program immediately ensued, using techniques such as knowledge mapping and the appointment of Local Knowledge Champions.

This paper will discuss in detail the balanced scorecard approach that was critical for timely adjustments in strategy and scope, the change management interventions that were undertaken, and the application of lessons learned and the best practices that resulted in a successful KM program. This success is evidenced by a decrease in the top failure modes, a decrease in the cost of poor quality, and an increased awareness of correct procedures and processes.