bluuebunny/crossref_metadata_2025_split huggingface dataset:
Inflow Performance Relationship for Perforated Horizontal Wells
Authors: Yildiz Turhan 
Published: December 2007

Abstract
This paper presents a comprehensive investigation of perforated horizontal well performance in areally anisotropic reservoirs. Theoretical investigation is based on a general 3D analytical IPR model. The analytical IPR model considers an arbitrary orientation and distribution of perforations along the completed segments. Changes in flow rate, pseudo-steady state productivity, and cumulative production can be computed using the solution.
The analytical IPR model was compared with the models available in the literature and verified. It was then used to investigate the effects of well and reservoir parameters on the inflow performance of partially perforated horizontal wells.
Prediction of Specific Productivity Index for Long Horizontal Wells
Authors: Cho Hyun , Shah Subhash N. 
Published: December 2007

ABSTRACT
As the length of a horizontal well is increased, its drainage area also increases. Productivity of a long horizontal well is no longer proportional to the well length because increase in the length of horizontal production section also causes frictional losses in the wellbore. However, no reliable standards are currently available that take into account quantitatively the parameters necessary for the calculation of productivity index in long horizontal well.
A new approach of the specific productivity index is proposed to predict the production rate considering friction losses in long production section under inflow conditions. This paper specifically describes model development, solution and the simulation results for the production of a long horizontal well with the specific productivity index. This specific productivity index is derived by assuming steady-state flow of a slightly compressible fluid in an anisotropic formation. The influence of wellbore damage near the horizontal wellbore is also considered in the model. The sensitivity study of the various parameters affecting productivity is performed and the results are analyzed quantitatively. The study shows that there is a critical point, where rate of friction pressure is suddenly increased and productivity index is decreased abruptly with increase in horizontal well length beyond this point. This critical point is the tangent point on which friction losses should be considered for production estimation. The model facilitates determination of the new horizontal productivity index considering friction losses in long horizontal wells.
Liquid Petroleum Confinement System
Authors: Pierson R. M. , Lucken J. E. , Shaver H. W. 
Published: December 2007

Abstract
The Liquid Petroleum Confinement System, (L.P.C.S.), has been designed and constructed to prevent the loss of produced crude oil into the Earth's atmosphere by retention and storage in a confined system. Historically, the petroleum industry has stored produced crude oil at individual surface well locations incorporating one or more standard atmospheric stock tanks. Crude oil stored in this manner undergoes certain physical changes, due to the vapor pressures of the escaping major constituents of the crude oil being greater than atmospheric pressure, causing "differential" and "flash vaporization". The crude oil in this physical state is observed in the form of gas and can be described by applying Boyles Law and Charles Law into the "Ideal Gas" equation PV = nRT. Any change in volume, temperature or pressure with respect to the crude oil, at the constantly changing physical and atmospheric conditions under which it is stored, causes a loss of the crude oil to the atmosphere. This loss can be as high as 50% or more of the daily produced crude oil volume resulting in atmospheric pollution and contamination as well as lost revenues to both the working interest and royalty owners. The L.P.C.S. provides an environment of storage in which the rate of vaporization and condensation become a steady state of "dynamic equilibrium". Thus the molecules of crude oil entering the vapor phase in random motion strike the surface of the liquid and are recaptured. The excess molecules can also be returned to collection and used as an on site fuel gas. The L.P.C.S. offers working interest and royalty owners' protection from the loss of production while increasing crude sales. The L.P.C.S. helps to prevent atmospheric pollution and contamination and becomes a highly efficient investment alternative to conventional atmospheric stock tanks and expensive vapor recovery systems.
Use of Concrete Technology for High-Density Cement Systems in South Texas
Authors: Pokhriyal Jai , Gaudlip Tony , Suter William R. 
Published: December 2007

Abstract
Historically cementing the deep high-pressure, high temperature (HPHT) gas wells in South Texas has often exceeded the capabilities of existing technology. The high-density mud systems and narrow margin between pore and fracture gradients require efficient mud removal and stable slurries with low equivalent circulating densities, and effective gas migration control, especially when cementing ‘slim hole’ completions. The high bottom hole temperatures along with the use of long liners where the static temperature at the top of liner (TOL) is often less than the bottom hole circulating temperature (BHCT) place additional requirements on the slurry designs to ensure early compressive strength development at the TOL.
A liquid concrete slurry system based on optimizing the packing volume fraction (PVF) of the dry blend using sized inert particles provides a cost-effective solution to cementing these HPHT wells. Using the concept of liquid concrete technology, slurry properties are a function of the dry blend rather than additives. Adjusting the particle size distribution enables the density, compressive strength and rheological properties of the slurry to be tailored for specific well conditions. The use of inert particles reduces the concentration of cement additives by approximately 50% making it possible to have extended pump times while ensuring rapid compressive strength development at the TOL when using an inorganic ‘set control’ additive.
By optimizing the PVF of the dry blend the permeability and porosity of the set cement are reduced due to improved particle packing. This makes it possible to provide a cost-effective solution to annular gas migration control.
High-density concrete slurries from 16.5 PPG to 23.0 PPG have been utilized to successfully cement HPHT gas wells with bottom hole circulating temperatures in excess of 400 °F. These slurries exhibit low rheologies, fast early compressive strength development and effective gas migration control.
This paper outlines the development and application of high-density liquid concrete slurries and their utilization in cementing HPHT gas wells in South Texas.
Laboratory Instrumented Sucker-Rod Pump
Authors: Podio A. L. , Gomez Jaime , Mansure A. J. 
Published: December 2007

Abstract
Although sucker rod pumps are installed in nearly 90% of all oil wells in the United States and have been widely used for decades, there are many issues regarding their performance that are not well understood. This is due to the difficulty of obtaining downhole pump-performance data. Many persistent problems in sucker rod pumping including partial pump fillage, gas interference, gas locking, fluid pound, sticking valves, rod downstroke compression loading, equipment failure, reduced production, etc. are difficult to diagnose from the surface. Currently, verification of sucker-rod pump problems can only be inferred by removal of the pump at great expense. Thus, root cause analysis depends on guesswork and component analysis. Knowledge of pump characteristics downhole would allow problems to be predicted rather than simply diagnosed after they have persisted long enough to result in failure
To develop a knowledge base of sucker-rod pumps, a two-fold approach is being pursued: first, instrumentation of a clear sucker-rod pump in the laboratory followed by the development of an instrumented downhole pump. The laboratory pump allows the development of diagnostic techniques where the pump performance can be verified visually. The downhole pump will allow testing at field conditions.
A key element to both the laboratory and downhole instrumented pumps is measuring the compression chamber pressure -- pressure within the pump barrel. The instrumentation has been designed to collect high-speed (≥100 samples a second) data so that transient behavior (ball chatter, etc.) can be observed. Data is being archived operating the pump under a various conditions from full to pumped-off.
This paper presents results of tests with the laboratory pump that have resulted in new insights about pump friction and the development of techniques to measure dynamic and static pump friction. Analyses of the compression-chamber pressure are leading to a better understanding of what happens during that time when both valves are closed and to the development of techniques to perform real-time diagnosis determining fillage and gas locking. Laboratory data has shown that compression chamber data can be more insightful in understanding pump conditions.
Case History of Hydraulic Fracture Optimization in Tight Gas Wells with Water Production in the Wind River Basin, Wyoming
Authors: Dempsey Brett J. , Taki Hadir , Druyff James C. 
Published: December 2007

Abstract
The Cooper Reservoir is located in the north-eastern end of the Wind River Basin. Wells are completed in the lower Fort Union and Lance formations at true vertical depths from 3300 to 8200 ft. Fracture treatments are complicated by water producing sands interspersed among up to a dozen or more gas producing sands as well as mobile water within the gas producing zones. An extensive data set of core analysis, rock mechanics testing, pre- and post-fracture well logs, pressure build up analysis, detailed fracture modeling, and detailed production analysis was compiled on 56 completions in order to better understand and evaluate well performance and stimulation effectiveness in this field. The evaluation is based primarily on the use of the reciprocal productivity index (RPI) graphical production analysis method. RPI uses daily production and wellhead pressure data to determine the effectiveness of the treatments by several parameters including flow capacity (kh), reservoir flow geometry, drained volume (area), and effectiveness of produced liquids management. Significant variations in reservoir quality and completion effectiveness were observed.
Problems Calibrating Production and Seismic Data for Fractured Reservoirs
Authors: Brown R. L. , Gupta A. , Wiggins M. 
Published: December 2007

Abstract
The permeability and seismic properties of fractured reservoirs are not easily correlated. A part of the problem is that seismic properties are controlled by the elastic properties of the rock grains, the pore-space/crack-space geometry, the connectivity of the pore spaces and any local flow that occurs during the transmission of the seismic signal. Permeability, however, is governed by the pore-space geometry, the effective length and apertures of the cracks as well at the connectivity of the cracks. One way to calibrate the permeability and the seismic is to identify a "sweet spot" within a reservoir where certain simplified assumptions can be made regarding the fracture permeability. Under these ideal conditions, it is possible to correlate the seismic response and the production data using simplifying assumptions. After the calibration is accomplished at the well control, these results can then be used to predict the permeability variations away from the well control using the seismic response and models for the relationship between the permeability and the seismic properties. This approach requires the development of empirical relations between the seismic response and the permeability of the reservoir.
Case Study: A Step-Change and Continuous Improvement in Safety Performance
Authors: Meckert J. P. , Stephens M. E. 
Published: December 2007

Abstract
The contract drilling industry continues to injure too many people, especially U.S. Land. Industry's improvement has been slow, erratic and current accident rates remain high. U.S. Land contract drilling is most concerning, as this category of IADC's Accident Statistics Program consistently performs worst.
Drilling contractors must take responsibility, and establish their own standards for safety. Today, the contractor / operator relationship is governed by contracts containing "knock-for-knock" indemnities and independent contractor status, and widely varying degrees of both operator safety support and drilling contractor safety ownership. Also, government authorities, such as OSHA, mandate that employers provide a safe workplace. Drilling contractors cannot be dependent on operators, nor government authorities, to provide, impose and / or enforce safety standards.
In 1997, Nabors Drilling USA, Inc. ("NDUSA") made a commitment to create a step-change and continuous improvement in safety performance under the belief that all of its 5000 employees should return home without injury at the end of work. While NDUSA had historically performed better than industry peers, the company was not satisfied and thus established a framework, devoted the resources and set standards to achieve consistently challenging goals. During the subsequent three years, NDUSA and the industry experienced one of its most volatile and difficult operating periods in history.
Since October 1997, NDUSA has achieved an 80% reduction in LTA incidence rate, 70% reduction in recordable incidence rate, and avoided 655 employee injuries. If NDUSA is compared to IADC's U.S. Land overall rate in 1998 and 1999, NDUSA alone prevented 90 workers from experiencing lost-time accidents and 250 overall recordables.
From both a moral and economic standpoint, the effort is justified. If the whole U.S. Land industry had adopted such measures and achieved similar goals in 1998 and 1999, U.S. Land companies would have avoided a total of 445 (or 63% of) lost-time accidents and 1,225 (or 40% of) recordables.
Redefining the Environmental Envelope for Surface Bops on a Semi-Submersible Drilling Unit
Authors: Gallagher Kevin T. , Bond David F. 
Published: December 2007

Abstract
One of the primary drivers for the deepwater exploration is currently the rig size to be able to support a large heavy riser and subsea BOPs. This in turn limits rig availability, which significantly increases rig rates. Surface BOPs (surface stack) offer an opportunity to utilise much smaller semi-submersible rigs and prelaid moorings, provided the system could manage the environmental conditions.
Woodside Energy Limited has designed a surface BOP (SBOP) and high-pressure riser system to be used on semi submersible drilling units for exploration drilling in the harsh environment of the North West Shelf, in Western Australia. In order to comply with Safety Case legislation in Australia the process described in this paper included system analysis, risk assessment and detailed design.
The end result was a SBOP system with several unique features that allow operations in harsher operating environments than have previously been considered with this technology. These include novel slip joint design, BOP support configuration and a unique seabed arrangement. The seabed arrangement allows management of the environmental loads, ability to weight shed the casing loads and mechanically disconnect / re-connect. The ability to re-connect also permits the suspension and or conversion of the well from an exploration to a production well offering significant cost reduction potential for sub-sea completions.
A Novel Approach To Slim Well Delivery
Authors: Erivwo O. E. , Owoeye O. O. , Ogoke V. C. 
Published: December 2007

Abstract
With the need to maintain competitive advantage in a low and volatile price environment, a cost leadership initiative was proposed to slim down Imo River 66 (EX-SDTQ-2) to achieve a 25% reduction in capex without compromising its offtake potential. A novel approach was used in the 7-5/8" x 5-1/2" x 3-1/2" single skin well configuration with 3-1/2" expandable sand screens (ESS) deployed in the horizontal section. The ESS was expanded to 4-3/4" which maximised the completion liner size and minimised the drain hole annulus thereby enhancing effective reservoir management. This paper presents the conceptual design and planning of the slim well. It also focuses on the critical issues and key challenges that were addressed to successfully drill the well and deploy the ESS.
The success of Imo River 66 resulted in a savings of 2.3 million dollars (32% cost reduction). The well proposed with a potential of 3000 bopd has already been tested to a post clean up potential of 3106 bopd at a lower bean size. This success has provided opportunities for step change reduction in construction costs of future wells with similar potential. It has also opened up new vistas in development options for brown fields and further optimisation opportunities in well design.
Fracture Gradients in Depleted Reservoirs - Drilling Wells in Late Reservoir Life
Authors: Alberty M. W. , McLean M. R. 
Published: December 2007

Abstract
A key requirement to successful drilling is the selection of a mud weight that provides sufficient pressure to prevent the influx of formation pore fluids, while at the same time not exceeding the fracturing resistance of formations exposed in open hole. The correct prediction of how pore pressure and fracture resistance varies through the intervals to be drilled is critical to designing an appropriate casing program.
In many instances fracture gradient profiles will be well defined from experiences of drilling offset wells. However, in cases where casing programs are modified or sub-subsurface conditions have altered, for example as a result of pressure depletion, predictive methods are required to extrapolate the previous measurements and inferences of the fracture gradient. Conventional wisdom on fracture gradients suggests that pressure depletion can significantly reduce fracture resistance and seriously increase drilling difficulty. However, an alternative theory on fracture gradients, coupled with growing evidence of its applicability, indicates that sands are not in general the cause of losses associated with induced fractures. Despite sands often being under lower in situ stress than adjacent shale layers, it is in fact the shale that are more likely to host an induced fracture responsible for large-scale mud losses. In general, shale has a higher Poisson's ratio than sands. In addition, the extent of pressure depletion will be less in intra-reservoir shale than in the sand layers. Therefore, the predicted effect of reservoir depletion on the fracture gradient is much less if based on the shale intervals than if based on the sands.
Here the theories on fracture gradients and the reasons for their differences are discussed. Field examples supporting the more optimistic approach are presented.
How to Diagnose Drilling Induced Fractures in Wells Drilled with Oil-Based Muds with Real-Time Resistivity and Pressure Measurements
Authors: Bratton T. R. , Rezmer-Cooper I. M. , Desroches J. , Gille Y-E. , Li Q. , McFayden M. 
Published: December 2007

Abstract
Major problems are often encountered in relaxed basins when extended reach wells are drilled through depleted reservoirs. As wellbore inclination increases, the imbalance between vertical and horizontal stresses can cause formation breakouts leading to increased cuttings and increasing the potential for stuck pipe. Higher mud densities can stabilize the imbalance and facilitate cuttings transport, but increase the risk of differential sticking and lost circulation. Additionally, higher mud densities can create fractures that take mud while drilling and return mud during connections. This ‘ballooning’ or ‘weeping’ complicates the correct diagnosis and increases the risk of losing the well. Early identification of these competing mechanisms can be critical to successful drilling.
Real-time resistivity-at-the-bit images are now possible to aid diagnosis, but are currently limited to water-based muds, and a limited range of conductive oil-based muds (OBMs). Nevertheless, conventional resistivity measurements can still be used in wells drilled with OBM. A case study is described of a highly deviated Gulf Coast well drilled with synthetic OBM that penetrated a severely depleted reservoir. Based on the data collected the original assumption that depleted sands were the only source of lost return zones was in error. The losses were found to be in the bounding shales as well. After losing two wellbores, the project was abandoned due to wellbore instabilities and limited reserves.
Investigations into the lessons learnt highlight how multiple passes with both resistivity and annular pressure measurements could have been used to diagnose the location and mechanism of borehole failure, and hence suggest appropriate action. Indeed, the resistivity measurements were found to be responding to induced fractures hours before any changes in equivalent circulating density (ECD) or significant drilling observation.
A methodology is given for diagnosing drilling induced fractures from the real-time measurements, so that remedial actions can be promptly taken. Success in future operations will come from including these new methods into the drilling plan.
Successfully Drilling Highly Depleted Sands
Authors: Shaughnessy John , Fuqua Ron , Romo Louis 
Published: December 2007

Abstract
BP has successfully drilled with up to 13,000 psi differential pressure through a depleted sand in a South Louisiana well. Close attention to operational procedures avoided stuck pipe and unmanageable mud losses. Bit selection and performance, BHA design along with mud system, cement program and casing design will be reviewed. Total costs were reduced by avoiding downtime associated with the high differential and by managing the sand without increasing casing sizes.
Drilling with Aerated Fluid from a Floating Unit. Part 1: Planning, Equipment, Tests, and Rig Modifications
Authors: Santos Helio , Rosa Fabio , Leuchtenberg Christian 
Published: December 2007

Abstract
Underbalanced Drilling (UBD) can be compared today with the horizontal drilling technology 15 years ago. Most probably, the majority of the wells will be drilled underbalanced in the near future. While onshore and offshore operations from fixed platforms have been conducted, UBD from floating units is still a challenge. With the majority of its hydrocarbon reserves located in deepwater, Petrobras decided to start a project to develop technology to drill wells with light-weight drilling fluid from a floating platform. This technology is seen today as the first step to reach UBD from a floating vessel, including deepwater locations. The present paper describes the steps taken so far to develop all the new equipment required and the HazOp meetings to discuss and approve the technical details and procedures. The paper also discusses the difficulties encountered during the negotiations with a rig contractor, to allow and fully understand the operation on board of one of its platforms. The paper finally discusses the best options from the lessons learned so far to have rigs ready to use this technology in the near future.