bluuebunny/crossref_metadata_2025_split huggingface dataset:
Vibration Analysis, Model Prediction, and Avoidance: A Case History
Authors: Samuel G. Robello , Schottle Gary , Gupta D. B. , Drilling Halliburton 
Published: December 2007

Abstract
In recent years, there has been a greater emphasis on technical limits with respect to drilling operations. Oil and gas companies strive to be amongst the highest ranked in operational efficiency with respect to industry related benchmarking statistics. Increasingly complex drilling scenarios, both surface and down hole, coupled with extremely high operating day-rates provide a challenging environment for those partaking in such operations. The risks are high, but the rewards are as well. Companies that can operate efficiently in such scenarios will most certainly reap the rewards.
Understanding technical limits and achieving operational excellence requires proper planning. Unfortunately, proper planning is only a part of the equation. The complexity of the subsurface environment generally results in deviation from planned operations. These deviations may result in significant non-productive time or in equipment failure. Reducing such incidents requires knowledge that the incident took place. Knowledge that the incident took place requires accurate data mining and retrieval as there may be significant time between operations, and knowledge transfer can be lost due to personnel changes. Additionally, an understanding of the root cause of an incident needs to be understood to prevent future incidents. This is generally more difficult to get a handle on. Applying post failure analysis utilizing engineering software applications is an essential part of determining the causes of non-productive time incidents and equipment failures. One could also surmise that it is a critical part of the planning process even though the analysis is after the fact. Reviwing lessons learned is a critical part of any planning process.
In high risk, high cost environments, such as ultra-deep, ultra-deep waters, refining advanced technologies for successful completion of wells is paramount. Challenges are still very much associated with complex BHAs (bottomhole assemblies) and with the vibration of the drillstring. The more widespread use of sophisticated downhole tools — for both directional telemetry and for logging while drilling applications (as part of the front line data acquisition system within the drilling process) — has meant that reliability is of prime importance1–5. This paper presents and validates an existing model to predict severe, damaging vibrations. The paper also reviews analysis techniques and guidelines to successfully avoid the vibration damage to downhole tools and their associated down hole assemblies.
Predicting the Flow Distribution on Total E&P Canada's Joslyn Project Horizontal SAGD Producing Wells Using Permanently Installed Fiber-Optic Monitoring
Authors: Krawchuk P. , Beshry M. A. , Brown G. A. , Brough B. 
Published: December 2007

Abstract
During the start-up and early operation of horizontal steam assisted gravity drained (SAGD) wells, it is important to understand the flow distribution of bitumen and water along the horizontal reservoir interval. If this distribution is understood, the distribution of steam, injected either at the heel or toe of the steam injector, can be adjusted to optimize the startup and early operation of the SAGD pair.
Total E&P Canada permanently installed optical fiber along their first Joslyn SAGD production well to monitor the temperature profile continuously during startup and production. Initial steam circulation and production occurred in 2004.
The acquired data shows that large temperature gradients exist across the wellbore during startup and early production, which is consistent with data from the observation wells. The injector-producer interval between SAGD wells was modeled with a thermal reservoir model to understand the influence of fluid viscosity, water cut, and permeability on fluid flow and the fiber optic measured temperature response.
By varying the injector-producer reservoir temperatures until the model temperature matches the measured distributed fiber optic temperature, it is possible to calculate the fluid viscosity in the inter-well region and consequently the flow distribution along the producing well.
Injector-producer temperature, which dictates the bitumen viscosity, was found to be the main parameter controlling flow in the injector-producer region. The results highlight the need for distributed temperature measurements in SAGD wells to facilitate understanding of the temperature response over time. The analysis demonstrates that it is possible to determine the flow profile from the distributed temperature measurement and thus optimize the injection of steam into the heel or toe of the injector well.
Bridging the Gap: Challenges in Deploying Leading Edge Geomechanics Technology to Reducing Well Construction Costs
Authors: Mody Fersheed K. 
Published: December 2007

AbstractOver the past two decades Geomechanics has made substantial contributions to the petroleum industry in the following areas: reducing well construction costs1,maximizing production2, andincreasing the life of the well.Currently the industry is venturing into more complex extended reach wells3, deeper water, higher pressure higher temperature environments, sub-salt settings4, lower pore pressure/fracture gradient margins, depleted zones5, fractured carbonates2 and fractured reservoirs6, environmentally sensitive areas, and many other difficult to develop situations, as illustrated in Figure 1.Geomechanics will play a significant role in addressing these added challenges. The high price of oil is here for a long time. Our technical responsibility is to make sure that the unit development cost (UDC) to produce this oil is contained and subsequently lowered with aggressive application of relevant technology and a knowledgable workforce adept at applying this technology.Being prepared to deal with the following issues will be integral to success: borehole (in)stability7–12,lost circulation13,14,stuck pipe15,sand production16,17,casing collapse18,19,well failures20,formation damage21,sub-salt related issues2.Each of these problems can strike at any time if we are not vigilant and pro active in avoiding them. Prevention at the outset is more cost-effective than fixing these issues later. I propose we have to bridge the gap between people and technology to be effective in this age of oil industry geomechanics. See Figure 2.Controlling CostsGeomechanics-related issues cost the industry billions of dollars.22We cannot afford, as an industry, to lose billions of dollars on Geomechanics-related non-productive time (NPT) and associated loss in revenues.32Over the past decade, for the drilling industry on an average twenty two percent of the drilling budget can be attributed to wellbore related NPT. Fifty percent of this NPT is associated with geomechanics related (i.e. wellbore stability, Lost circulation, stuck pipe, etc.) issues.1, 811, 22, 32In spite of advances in technology, this NPT percentage associated with borehole related problems has not drastically changed over the past decade. NPT percentage of the total drilling budget is much too high and must be lowered to a more acceptable level.Also further scrutiny of the NPT data suggests a trend, that approximately 90% of costs can be attributed to a small percentage of wells that are highly complex. When these wells have problems, the cost escalates. See Figure 3. Hence, it is critical to manage the available geomechanics resources in the most optimal manner. It is important to identify the high mechanical-risk index wells and get the right geomechanics resources committed – both personnel and data collection – early in the planning stages of the well construction and utilize these resources throughout the well delivery cycle.
The Texture of Acidized Fracture Surfaces—Implications for Acid Fracture Conductivity
Authors: Malagon C. , Pournik M. , Hill A. D. 
Published: December 2007

Abstract
In an acid fracturing treatment, fracture conductivity is created by differential etching of the fracture surface by the acid – without non-uniform dissolution along the fracture face, the fracture will close after pumping ceases, and little lasting conductivity is created. In spite of this critical role of differential etching on the creation of fracture conductivity, little is known about the texture of the fracture surface created during acid fracturing, and the dependence of this texture on the acidizing conditions. To study this important aspect of the acid fracturing process, we developed a new surface profilometer for accurately and rapidly measuring the surface profile of a rock sample, and have used it to measure fracture surfaces after acidizing.
The profilometer measures the distance to the rock surface with a laser device that measures distance with an accuracy of 0.001 in. The rock sample is mounted on a servo table that automatically moves the sample in selectable increments that are typically 0.025 in. With this device the surface of a standard API fracture conductivity sample can be scanned in a few hours and a digitized profile image can be obtained. This digital image is used to quantitatively characterize the etched surface topography.
We have measured the etched fracture surface profile for a wide range of acidizing conditions. The etched surface characteristics depend very strongly on the acidizing conditions, including acid type and strength, solution apparent viscosity, velocity in the fracture, and leakoff rate, and rock type. Results for typical acid fracturing fluids and conditions are presented as well as recommendations for fluid systems that create the most small scale differential etching.
Coupling of Downhole Dynamics Recorder Enhances System-Matched Approach to Drill-Bit Design and Application With a Specific Rotary-Steerable System
Authors: Barton S. , Lockley R. , Stroud D. , Peach S. 
Published: December 2007

Abstract
The combination of the large number of rotary-steerable systems (RSS) currently available and the variety of well trajectories in which they are applied requires a customized range of drill bits to optimize system performance. A clear understanding of the specific tool operation, combined with in-depth modeling and physical testing, is the ideal approach for determining the demands placed on the drill bit and thus deriving its key characteristics.
This paper describes a series of tests that were performed at a purpose-built drilling facility to examine the variation in directional response with different bit features. Steerability is one of the key criteria involved in RSS bit design, but stability is of equal importance, particularly in ensuring good-quality, gauge borehole for maximum steering potential. To monitor the testing, a proprietary downhole dynamics recorder was used. The recorder consists of a small, sophisticated electronic measuring device that can be either housed in a sub or positioned in a specially modified housing within an existing drillstring component. The recorder was used to gather actual downhole data at a high frequency sample rate to determine both the lateral and torsional stability of the drill bit and RSS assembly with different wellbore trajectories and parameters.
Results identified that specific gauge features are crucial to the directional response of the RSS tool. In addition, the dynamics recorder allowed quantitative assessment of stability versus steerability of the critical drill bit features tested. Lessons learned from this laboratory testing have been taken to the drilling environment with excellent field results, demonstrating that matching the bit to a specific RSS tool as part of the system delivers proven drilling success.
Comprehensive Drill-Rate Management Process To Maximize Rate of Penetration
Authors: Dupriest F. E. 
Published: December 2007

Abstract
The operator's drill rate management process is designed to maximize rate of penetration (ROP) in every foot of hole drilled. Due to its quantitative nature and the degree to which it is incorporated into all phases of the drill well process, the operator believes it to be the industry's first comprehensive ROP design process. The workflow is being implemented uniformly across an organization drilling approximately 4.5 million feet of hole per year in a wide range of rock types, directional profiles, and international locations. The results to date have been similar in most applications with significant gains in ROP, bit life, and reduction in tool failures related to vibrations.
The workflow evolved from surveillance techniques the operator developed to utilize Mechanical Specific Energy (MSE) surveillance to evaluate drilling performance in real-time(1),(2). MSE surveillance proved to be an effective aid in identifying bit and system inefficiency. However, having this knowledge does not ensure the team knows why the inefficiency is occurring, or how to correct it. There are organizational processes that must also be considered when mitigation of the problem involves increased mechanical risk, significant changes in established practices, or a high level of technical training. MSE is a technology, while the ROP management process is a broad workflow designed to ensure MSE and numerous other sources of data are used effectively to maximize ROP. Consistent implementation of the workflow has been shown to achieve consistent increases in ROP. The key elements of the workflow required to achieve this performance are discussed.
Over 40 categories of ROP-limiters have been identified, of which only 4 are directly related to the bit. The ROP in a large portion of footage drilled is constrained by factors other than bit performance, which are referred to as non-bit limiters. The workflow addresses both bit and non-bit limiters equally, and includes a simple model to aid drill teams in prioritizing the large number of potential ROP-limiters so resources available for surveillance and redesign are used most effectively.
Performance improvements have been sustained since the staged rollout began in late 2004, and additional gains are continuing. Performance data is included, as well as a discussion of key implementation learnings.
Development of Low-Order Controllers for High-Order Reservoir Models and Smart Wells
Authors: Gildin E. , Klie H. , Rodriguez A. , Wheeler M. F. , Bishop R. H. 
Published: December 2007

Abstract
Recently, the oil industry has started instrumenting and deploying various controls for the enhancement of hydrocarbon extraction. However, due to system complexity, data acquisition and, in turn, decision making, are still issues to be resolved in large-scale reservoir management. A very challenging large-scale control problem that has emerged recently is the real-time control of smart wells. A fundamental reason for using feedback control in this setting is to achieve desired performance in the presence of external disturbances and model uncertainties.
This work introduces iterative Krylov subspace projection (KSP) methods to generate low-order feedback controllers for smart wells employing high-order reservoir models. The main motivation for using these methods is to enable the efficient computation of low-order reservoir models derived from the highly sparse structure of fluxes and pressure coefficients after discretization. Compared to other model reduction methods, such as modal decomposition, balanced realization, subspace identification and the proper orthogonal decomposition (POD), the proposed approach is very efficient since it is fundamentally based on sparse matrix-vector products. For a problem size of n simulation gridblocks, the KSP method presents a complexity of O(n2k) (or even O(nk), by exploiting sparsity), where k is the number of iterations required to generate the low-order model. This is highly desirable for the design of timely low-controller mechanisms in smart wells.
We illustrate the potential of the method by linearizing an oil-water model and showing how to establish stability and error bounds for production responses under certain perturbations. We also discuss how the method can be extended to cases of non-stationary and nonlinear fluid coefficients.
Modeling Low-Salinity Waterflooding
Authors: Jerauld G. R. , Lin C. Y. , Webb K. J. , Seccombe J. C. 
Published: December 2007

Abstract
Low salinity waterflooding is an emerging EOR technique in which the salinity of the injected water is controlled to improve oil recovery over conventional higher salinity waterflooding. Corefloods and single well chemical tracer tests have shown that low salinity waterflooding can improve basic waterflood performance by 5 to 38%. This paper describes a model of low salinity flooding that can be used to evaluate projects, shows the implications of that model, demonstrates its use to represent corefloods and single well tests as well as field scale simulations, and gives insight into the reservoir engineering of low salinity floods.
The model represents low salinity flooding using salinity dependent oil/water relative permeability functions resulting from wettability change. This is similar to other EOR modelling and conventional fractional flow theory can be adapted to describe the process in one dimension for secondary and tertiary low salinity waterflooding. This simple analysis shows that while some degree of connate water banking occurs it need not hinder the process. Because mixing of injected water with in situ water delays the attainment of low salinity, potentially preventing attainment of low salinity all together if very small slugs of low salinity water are used, care must be taken in representing mixing appropriately in interpreting data and in constructing models. The use of numerical dispersion to represent physical dispersion in 1D, radial and pattern simulations of this process is demonstrated, i.e. coarse simulations are shown to give the same result as fine grid simulations with appropriately large physical dispersion. In many applications, the fine grid simulation necessary to represent appropriate levels of dispersion is not practical and pseudoization is necessary. We demonstrate that this can be done by changing the salinity dependence and shapes of relative permeability curves.
Coiled-Tubing Perforation and Zonal Isolation in Harsh Wellbore Conditions
Authors: Omar M. I. , Ali A. Md , Ali Z. , Parapat A. , Speck W. , Parta E. 
Published: December 2007

Abstract
Coiled tubing has been widely used worldwide to perform perforating and zonal isolation operation due to the ability in intervening highly deviated and long section of horizontal wells under live condition, where slickline and E-line have difficulties.
This paper presents case history of coiled tubing perforating and zonal isolation evolution in infill well at Resak field, one of the gas field operated by Malaysia National E&P Company, Petronas Carigali Sdn Bhd.
Since the beginning of Resak Field production, coiled tubing has been used to perforate numbers of infill wells with low success ratio. The reservoir characteristics with high formation pressure and BHT followed by high CO2, H2S production and improper well clean up contributed in the increase of operational risks and challenges. Several failures reported in the past was carefully analyzed to determine the actual root cause prior to coming up with the proper job design and operational procedures.
CTU with 1.5" CT reel was used to convey 140 ft of 2-7/8" gun due to crane and platform deck loading limitation. The small CT size and large gun conveyance required extra precaution since the presence of gun shock during perforation may affect the CT integrity. Therefore supporting perforating software was run in advanced to optimize gun selection where both operational risks and production objectives were taken into consideration. Coiled tubing forces simulation was also used to determine the ability of the gun assemblies to be safely conveyed into the target sands. In addition to that, one of the unique features from the gun assemblies was the selection of electronic firing head over a conventional or standard drop ball mechanism. This tool utilized coded sequence created from variation of surface pump rate to generate its firing command, providing reliable gun activation where as the drop ball mechanism in the past was found to have some operational difficulties.
Lastly, this paper also mentions the proper selection of zonal isolation method that can withstand the wellbore condition, providing adequate isolation whilst able to be retrieved for future production requirements. The result of those engineering studies managed to overcome the operational failures in the past and at the same time was able to meet the production objective.
Project Result
After performing the coiled tubing operation by isolating J10.2 with inflatable bridge plug and perforating J10.1 with deep penetration gun, the well managed to be produced at 22.7 MMSCF/D & stabilized at 48 MMCSF/D (23 % choke size) with total gain of 41MMSCF/D which was higher than the expected gain of 35 MMSCF/day (Figure 1). Currently the well is the highest producing well in Resak field with stable production at 49.8 MMSCCF/D. Figure 1Production Data before and After CT Perforating
Challenges for Everyday NMR: An Operator's Perspective
Authors: Akkurt R. , Kersey D. G. , Zainalabedin K. 
Published: December 2007

Abstract
State-of-the-art Nuclear Magnetic Resonance (NMR) applications can be classified into two categories: (1) basic applications designed for total porosity, bound water and permeability, (2) advanced applications that address hydrocarbon type, viscosity and flushed zone hydrocarbon saturation, amongst some others.
An NMR log designed for basic applications – especially a T1 log – can provide accurate porosity information in shaly sands and complex carbonates; answer questions related to reservoir quality and producibility; and easily identify gas or tar zones. Given the obvious benefits of such information for routine petrophysical analysis and timely business decisions, one would assume that NMR logging would already be an everyday phenomenon in formation evaluation. Unfortunately, NMR has yet to enter the main stream of everyday logging: it is still considered a specialty, requiring the involvement of experts from the planning to the interpretation stages.
Partially due to historical reasons, but more so for cost justification and product differentiation, service companies have traditionally focused on advanced applications. Hence, despite significant advances made in all phases of the technology, concentrating on sophisticated methodologies has resulted in slow logging speeds and high costs, in addition to complex data acquisition, processing and interpretation procedures.
Turning the everyday-NMR concept into a reality will require standardization of the service and proper hardware that is free of the limitations of the existing tools. The main objective of this paper is to discuss specific strategies to achieve the everyday-NMR goal for wireline and LWD logging. The proposed strategies include not only the technical requirements, but also the initiatives required from both the operators and service companies.