bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improved Deepwater Cementing Practices Help Reduce Nonproductive Time
Authors: Vargo R. F. , Heathman J. F. , Kellingray D. S. , Ward M. D. , Lummus J. M. 
Published: December 2007

Abstract
Over the course of a 4-year period, during which approximately 42 wells were constructed by this operator, processes were developed to improve cement slurry design and reduce nonproductive time (NPT) during cementing operations on deepwater wells.
Cementing best practices have been followed for many years; however, not all of these practices are applicable to deepwater operations, especially for the riserless sections. Results of developing (1) slurry design practices, (2) temperature prediction and mud removal modeling, and (3) the use of SSR® subsurface release plugs will be reviewed.
The choice of cement blend used can have a profound impact on cost, not only in terms of failure in the event of the wrong design, but also in terms of supply logistics. As deepwater operations move farther away from shore bases, the need for a systems approach to cover all cement design needs from conductor to plugging should be considered. The challenges across this breadth of application range from dealing with shallow water flow potentials to relatively high temperature and pressure. Both conventional and foamed cement slurries can be successfully used in this endeavor when properly designed and placed. Placement design should include a thorough understanding of the static gel development behavior of the drilling fluid.
Although it is generally accepted that conventional circulating temperature estimates are not appropriate for use in deep water, the use of alternatives is not always practiced. Over the course of this project, this operator realized better cement slurry performance and lower slurry costs following the correct use of wellbore thermal simulators. Attention to detail in applying the correct data to computer simulations resulted in lower slurry costs while at the same time achieved improved performance as measured by improved casing shoe integrity.
Real-time monitoring and detailed pressure analysis were used to manage cementing operations and the correct application of SSR plugs. Feedback of these processes from operators and service tool personnel has resulted in improved job performance as measured through reduced NPT and well construction costs. These new processes have resulted in a 100% success rate as compared to the previous 74% success rate.
Effective High-Density Wellbore Cleaning Fluids: Brine-Based and Solids-Free
Authors: Javora P. H. , Baccigalopi G. , Sanford J. , Cordeddu C. , Qu Q. , Poole G. , Franklin B. 
Published: December 2007

Abstract
Displacing drilling mud with clear solids-free completion brine is a critical step during well completion. As we move into deeper waters and drill to deeper depths (greater than 25,000 feet MD), conventional methods and cleaning fluids become a limiting factor in this phase of the operation. Conventional cleaning fluids use fresh water or seawater treated with surfactants to remove wellbore solids and water wet tubulars. Using low-density cleaning fluids creates a negative differential pressure between the working kill weight fluid and the formation, casing and cement liners. In many situations, the negative differential pressure cannot be tolerated and the risk of failure at the liner top, etc. is increased, especially if the wellbore has not been pressure integrity tested. Additionally, with increasing rig / spread costs, high pump rates are necessary to decrease the time it takes to perform these operations. The pump rate is indirectly proportional to the pump pressures required. Weighted spacers decrease the overall pressure differential, which allows for higher pumping rates.
In order to overcome the density limitation of these cleaning fluids, conventional techniques such as additional hydraulic horsepower, backpressure schedules, the addition of solids to lighter cleaning fluids (water, seawater), or balancing the weight of the low-density cleaning fluid with a matching higher-density fluid is utilized. However, each of these "fixes" has inherent limitations and is accompanied with reduced cleanup efficiency. Furthermore, conventional surfactants are not active or effective in high-density brines. New brine-compatible surfactant chemistry and the corresponding balanced-displacement engineering design were developed to overcome limitation of conventional displacement technology.
This paper describes the field applications of new brine-based high-density solids-free cleaning fluids in balanced-displacements in deepwater and offshore shelf wells. The new high-density fluids were based on, new surfactant technology developed to ensure effective wellbore cleaning, wellbore design parameters, and displacement modeling. In addition, weighted spacers aid in reducing high pump pressures and wellbore pressure differentials. In one case history, maximum pumping pressure of more than 9,000 psi was expected for conventional water based displacement, but was reduced to a little over 3,000 psi with the new design. High-Density cleaning fluids, with densities up to and greater than 17.5 ppg, have been formulated and utilized successfully without compromising cleanup efficiency and significantly reducing differential pressures. Results from laboratory development and field applications are presented.
Visualization of BHA Dynamics Improves Understanding of Downhole Drilling Conditions, Speeds Up Learning Curve
Authors: Jogi P. , Macpherson J. , Neubert M. , Reckmann H. , Heisig G. 
Published: December 2007

Abstract
The drilling industry demographics predict a significant loss of expertise in the upcoming years as a high percentage of drilling personnel will reach retirement age. At the same time, drilling activity is predicted to grow driven by high oil prices based on strong demand. As rig rates go up, failures in downhole drilling equipment as a result of downhole conditions will become even more costly, resulting in an increased demand for experienced personnel. There is, therefore, a widening experience gap that needs to be addressed as fast as possible.
Over the past few years, the service industry has developed sophisticated downhole1,2,3 and surface data acquisition systems that can record critical drilling parameters at a level of detail and accuracy not available before. In particular, on the downhole side it is now possible to store significantly more data at a fraction of the cost compared to earlier years. However, while more data are now available, the analysis is still done in the traditional manner via logs or special signal processing systems requiring a high level of expertise. As a result, large amount of data are acquired today, but only few experts are available to do a detailed analysis so that a lot of the data are never looked at.
Visualization tools can be a solution to this dilemma. They can provide a much faster learning curve about downhole conditions while drilling. Computer animations facilitate re-playing data recorded downhole at a high rate, displaying the motion of a downhole tool inside the borehole. Combining downhole data with BHA modeling software allows the user to review the mechanical loading of the BHA in the section just drilled, and to focus attention on special events or sections as necessary.
The paper reviews dynamics data sources and formats available today and present several example displays and animations that show how visualization can aid the process of analyzing large amount of data. In addition to the visualization of recorded data, the paper also presents real-time visualization-while-drilling that is intended to enhance the drilling crew's understanding of the downhole conditions. The paper finishes with a short discussion of the benefits of using animations and visualization tools in training programs and education seminars.
Real-Time Downhole Torsional Vibration Monitor for Improving Tool Performance and Bit Design
Authors: Chen D. C.-K. , Comeaux B. , Gillespie G. , Irvine G. , Wiecek B. 
Published: December 2007

Abstract
A new downhole torsional vibration sensor built into a rotary steerable system has provided a new monitoring system for improving drilling efficiency and avoiding downhole failures related to torsional vibration. The strength of the new sensor is that it measures rotational changes right at the bit as compared to the usual 50-100 feet behind the bit with conventional MWD/LWD sensors. In addition, the sensor is always at the same location regardless of BHA configuration, which provides a higher level of consistency in torsional vibration measurement. The ability to evaluate bit performance objectively has consequently resulted in better bit design and rotary steerable tool performance.
The new torsional efficiency monitor has been used in areas where torsional vibration was recognized as a problem. This paper will discuss the application of the real-time downhole monitor and the results from detailed analysis of the data from the initial field runs in these harsh environments. The ability to immediately detect the occurrence of torsional vibration and to take corrective action before failures occur has significantly improved the ability of the rotary steerable system to survive harsh conditions.
Understanding the Pressure Gradients Improves Production From Oil/Water Transition Carbonate Zones
Authors: Carnegie A. J. G. 
Published: December 2007

Abstract
Worldwide, carbonate oil-water transition zones contain vast amounts of producible oil. Yet, traditional approaches to open-hole formation evaluation often fail to predict how much oil should flow from them, or even the location of the free water levels. A theory applying capillary pressure scanning curves shows how changing water saturations and variations in levels of mixed wettability systematically control the differences in the pressures of the invading mud filtrate and formation oil, to result in the following unusual yet often observed behavior: 1) negative pressure gradients, 2) water-like gradients significantly above the free water level, 3) significant shifts in the measured pressure potentials between the lower and upper part of the transition zone, 4) gradients implying an oil-density different to that which is expected. Supercharging effects are shown to be unimportant to the discussion. Both wells drilled with water based mud and oil based mud are considered. It is shown how it is usually possible to produce oil from a zone which has a water-like pressure gradient and low formation resistivity. The theory is supported by detailed analysis of examples from flow simulations, which recreate the well known field cases referred to above. Guidelines are presented on how to interpret traditional open hole pressure measurements in a carbonate oil-water transition zone to determine the free water level and the locations where oil should flow, and on how to improve on these interpretations by performing more advanced formation testing procedures, some of which are based upon new technology.
High-Quality Electrical Borehole Images While Drilling: Increased Confidence in Well Positioning and Drilling-Hazard Mitigation From Real-Time Data
Authors: Morris S. , Lofts J. , Lindsay G. , Fulda C. , Dahl J. 
Published: December 2007

Abstract
Recent developments in technology have lead to the ability to acquire and transmit high resolution electrical borehole images while-drilling. The advantage of imaging while drilling is to acquire data with minimal rugosity of the borehole wall and before appreciable invasion of the drilling fluid in order to obtain the best possible quality images. High quality, real-time images and the resulting ability to proactively steer the drill bit provide benefits to both the driller and geologist through the ability to make real-time decisions on optimum well placement. Further implications for the driller are reduction in NPT through drilling hazard mitigation and maintaining borehole stability because of the immediate identification of breakout. For the geologist, the real-time interpretation of structural and sedimentary information from electrical images can be used to steer the drill bit in order to: stay inside a desired sedimentary package based on the rapid interpretation of sedimentological criteria (e.g. sedimentary steering by using predictive models of sandbody geometry and internal architecture),give fore-warning of approaching features in the proposed drill path (e.g. fracture intensity increasing towards a fault zone), andavoid or mitigate adverse features that may have a negative impact on production (e.g. avoiding reservoir roof rocks by steering away in advance).
Field tests have shown the ability to transmit to surface real-time compressed images that can be optimized for deriving structural information whilst higher resolution images can be used for sedimentary analysis. This paper shows how these developments can be used to increase confidence in well placement, at the same time as avoiding drilling hazards.
Deployed Smart Technologies Enablers for Improving Well Performance in Tight Reservoirs—Case: Shaybah Field, Saudi Arabia
Authors: Salamy S. P. , Al-Mubarak H. K. , Hembling D. E. , Al-Ghamdi M. S. 
Published: December 2007

Abstract
Intelligent wells are becoming the buzz word in the oil and gas industry. Today the development and deployment of smart technologies are important drivers for improving well productivity and delaying early water or gas breakthrough in tight and challenging reservoirs.
Shaybah field, a low permeability reservoir overlain by a huge gas cap was initially developed in 1996 with one-km single lateral horizontal wells to effectively drain the hydrocarbon while reducing gas coning. A step development approach by increasing the reservoir contact to improve well productivity and performance was the basis for Maximum Reservoir Contact (MRC)1 concept. Maximizing reservoir contact through MRC wells was one of the measures taken in early 2002 to reduce gas coning and improve recovery. Results to date from 37 MRC wells have indicated a four fold increase in well productivities and a three fold decrease in unit development cost when compared to the one-km single lateral wells.
In addition, several advanced completion technologies such as downhole flow control systems (smart completions), expandable liners, and production equalizers were deployed in Shaybah Field. These technologies have shown major improvements to well performance and recovery. Smart controls assisted in optimizing production from each lateral in a multi-lateral setting in the event of premature gas or water coning. In addition, downhole smart completions improved well productivity in multi-lateral wells through an improved well cleanup process. Production equalizers when deployed in high GOR wells reduced gas coning by 50% and improved well productivity. To date, over ten expandable liners have been deployed as enablers to a workover strategy to convert single lateral wells to Multi-lateral/MRC wells thereby providing the platform for installation of downhole flow control systems. Shaybah Field holds several world records in the area of technology implementation; one of which is for the first MRC window to exit from 5-1/2" expandable allowing the placement of 2-7/8" ICV for inflow control. This paper will highlight how smart technologies have positively impacted field performance.
Generalized Analytical Solution for Reservoir Problems With Multiple Wells and Boundary Conditions
Authors: Busswell G. , Banerjee R. , Thambynayagam R. K. M. , Spath J. 
Published: December 2007

Abstract
We present a set of new analytical solutions to the single layer reservoir problem, both in real time and Laplace space. The solutions are derived assuming a cuboid shaped reservoir using a method of integral transforms. The method can be applied to calculate the pressure as a function of position and time when using any continuous function to describe the production rate of a point source. Successive integration of the point source solution can be performed to calculate the average bottom hole pressure of a well.
These equations are applicable to partially penetrating vertical, horizontal and fractured wells and take into account superposition effects in multi-well and multi-rate scenarios. Notably, regarding fractured wells, we are able to accurately model the case of a finite conductivity fracture with non-Darcy flow as well as those of infinite conductivity. The generality of our method allows any continuous function of position and time to be used to treat either pressures or fluid fluxes on the boundaries.
Also, using solutions in Laplace space we are able to model naturally fractured reservoirs, wellbore storage, non-Darcy D-factors as well as constant well pressure production, also all within a full field multi-well scenario. Our method, therefore, provides a powerful alternative to simulation in terms of reservoir modeling.
We present a comparison of our solutions with that generated using a commercial finite difference simulator for a variety of problems in terms of accuracy and speed. We find amazing accuracy with massive gains (factors&gt;300) in CPU times for fracture problems in particular.
Supercritical CO2 and H2S—Brine Drainage and Imbibition Relative Permeability Relationships for Intergranular Sandstone and Carbonate Formations
Authors: Bennion D. B. , Bachu S. 
Published: December 2007

Abstract
Sequestration of CO2 and H2S (acid gas) in deep underground formations is a means for reducing atmospheric emissions of acid gas produced from sour gas reservoirs that has been practiced for 15 years in North America and that is currently being considered in other regions such as the Middle East and central Asia. Furthermore, acid-gas injection operations constitute a commercial-scale commercial analogue to CO2 injection in geological media as a climate change mitigation measure. Deep saline aquifers provide a very large capacity for the sequestration of acid and greenhouse gases, being ubiquitous in all sedimentary basins around the world. Proper understanding of the relative permeability character of such systems is essential in ascertaining gas injectivity and migration, and in assessing the suitability, containment and safety of prospective injection sites.
Pure CO2 and H2S represent the compositional end-members of acid and greenhouse gases, thus the interest in measuring their displacement properties. This paper presents the detailed experimental equipment and protocols, and the results of a series of relative permeability tests conducted at full reservoir conditions using supercritical pure CO2 and H2S on samples of intercrystaline sandstone and carbonate rocks from the Wabamun Lake area in central Alberta, Canada, where large CO2 sources and several acid-gas injection operations exist. Results for both drainage and imbibition relative permeability experiments are presented for each fluid and rock type, as well as measurements of the interfacial tension (IFT) between brines and CO2 and H2S at in situ conditions, and correlations of these results with the IFT, measured rock capillary pressure, pore size distribution and mineralogical data. The results allow a comparison between the drainage and imbibition relative permeability character and performance of the two gases, and provide a valuable dataset for the evaluation and simulation of acid gas disposal and CO2 storage projects.
Case Studies: A Practical Approach to Gas-Production Analysis and Forecasting
Authors: Jordan C. L. , Fenniak M. J. , Smith C. R. 
Published: December 2007

Abstract
This paper illustrates a practical systematic approach to determine the reservoir flow characteristics and reserves for both conventional and unconventional gas wells. Currently, there is an industry assortment of production analysis methods ranging from exponential decline and typecurve matching to rate-pressure normalization techniques and detailed production history matching. Through real life cases studies it will be shown that it is possible that a simpler reservoir model, such as a single well completed in the center of a circular reservoir, could be used to represent far more complex reservoirs, and still provide some representative reservoir characterization, as well as accurate reserves analysis and production forecasting. As a result, it possible that engineers and the like can avoid some of the more labor intensive production data analysis (PDA) techniques, and use more a methodology similar in operation to traditional decline.
Case studies and experience presented in this paper will demonstrate that a simple approach of production analysis methods will allow for a) proper identification of flow regimes, b) reliable evaluation of drainage area and OGIP, and c) the prediction of future deliverability and depletion. Case studies will also show that up-scaled and aggregate reservoir properties can provide a real measure of gas well deliverability (therefore a simpler, time-efficient model analysis can be used). Data uncertainty, unconventional gas (i.e. coal bed methane, tight gas, shale gas), stimulation appraisal, and other factors will be discussed in the context of the case studies.
Prediction of Drillstring Fatigue Life Under Axial-Torsional-Combined Vibration
Authors: Chi A. , Zhang J. , Ge W. , Guo B. 
Published: December 2007

Abstract
Vibration of drillstring was found responsible for the severe damage and premature failure of drillstrings during drilling the gas-bearing igneous formations in the Songliao Basin, China. The vibration significantly shortened the life of drillstrings and had a great impact on drilling performance in the area. The objective of this study was to identify the key factors affecting drillstring vibration and develop a control-mechanism to reduce the failure rate of drillstring.
This study investigated the combined effect of axial and torsional vibrations on the damage of drillstring. A computerized model was built to simulate loads from axial and torsional vibrations. An analytical method for predicting the fatigue life of drillstring was developed. The method uses the output from the computerized model. Engineering charts were also generated for typical drilling conditions. These charts have been adapted in a Drillstring Damage Control Program implemented in the Songliao Basin, China.
Production Optimization—A Moving-Horizon Approach
Authors: Nikolaou M. , Cullick A. S. , Saputelli L. 
Published: December 2007

Abstract
Designing fluid injection policies to optimize the production of a hydrocarbon reservoir has attracted considerable interest in recent years. Production policies can emerge from numerical optimization analyses, the solutions for which are most frequently based on optimal control theory. In this paper we argue that (a) a simpler alternative to the optimal control approach may be used, and (b) we present a moving-horizon formulation alternative. We illustrate the proposed approach through several examples.