bluuebunny/crossref_metadata_2025_split huggingface dataset:
Post-Perforation Flow Models for API Recommended Practices 19B
Authors: Roostapour A. , Yildiz T. 
Published: December 2007

Abstract
Flow tests conducted on standard cylindrical Berea targets are used to evaluate the relative merits of jet perforators. The procedure and equipment for the flow tests are described in the API Recommended Practices 19B revised recently. The performance of the perforators is quantified in terms of core flow efficiency (CFE).
The CFE is the ratio of the actual post-perforation flow rate measured on the core to the theoretical ideal flow rate calculated from the mathematical models considering post-perforation flow geometry. The post-perforation flow tests may be conducted in several different flow geometries; axial flow, semi-radial flow, and radial-axial flow.
This study presents analytical solutions to predict the ideal rates for the complicated post-perforation flow configurations. The proposed solutions are compared against the existing numerical models and verified. The analytical solutions are general, and very fast and inexpensive to compute.
After verifying their accuracy, we use the solutions to evaluate the validity of the API recommended procedure and analysis technique. We demonstrate that the post-perforation flow geometry, core/perforation dimensions, permeability anisotropy, and the degree of formation damage control CFE. The same degree of formation damage yields different CFE in different post-perforation flow geometries. Finally we introduce a method to convert the CFE data to an equivalent skin factor for the perforated wells.
Determination of Parameters for Matrix-Fracture Transfer Functions From Laboratory Data
Authors: Civan F. , Rasmussen M. L. 
Published: December 2007

Abstract
Improved matrix-fracture interface fluid transfer functions for naturally fractured reservoirs are formulated and the associated parameters are determined by experimental data. Hindered-fluid transfer across the matrix-fracture interface due to skin effect is considered. Applications for single phase oil or gas production by pressure depression and oil production by immiscible displacement are accomplished by means of dimensionless phenomenological equations. Analytical solutions are derived for special boundary conditions involving the typical laboratory tests and reservoir simulation to represent the various matrix block shapes. The present analytical solutions involve the skin effect, anisotropic porous matrix, properly scaled variables, and full-time solutions and asymptotic solutions for early- and late-time periods. These solutions are obtained after proper linearization of the porous matrix fluid transfer model for one-, two-, and three-dimensional Cartesian matrix blocks, circular-cylinder and annular shaped matrix blocks, and spherical matrix blocks. The characteristic parameters of the transfer functions, namely the diffusion coefficient, skin coefficient, and skin thickness, are determined by conforming special analytical solutions to experimental data involving fluid exchange between matrix and fracture by imbibition.
The Application of Microemulsion Additives in Drilling and Stimulation Results in Enhanced Gas Production
Authors: Penny G. , Pursley J. T. , Holcomb D. 
Published: December 2007

Abstract
A new microemulsion additive has been developed that is effective in remediating damaged wells and is highly effective in fluid recovery and relative permeability enhancement when applied in drilling and stimulation treatments at dilute concentrations.The microemulsion (ME) is an optically clear, thermodynamically stable blend of biodegradable solvent, surfactant, co-solvent and water.The nanometer sized structures have extremely high contact efficiency at low concentrations (0.10-0.5%).
Lab data is presented that illustrates how the Microemulsion accelerates the cleanup of injected fluids in tight gas cores. The microemulsion additive results in lower pressures to displace injected fluids from low permeability core samples and proppant packs. The relative perm to gas is increased substantially as the water saturation is decreased. The enhanced relative permeability mechanism is the alteration of the rock-fluid interfacial tension or contact angle.It is demonstrated that this alteration effectively lowers the capillary pressure and capillary end effect associated with fractures in low perm reservoirs by as much as 50%, thus mitigating phase trapping and therefore permitting an increased flow area to the fracture and longer effective frac lengths.Examples of drilling fluids with and without ME are shown in which the relative perm to gas and oil are improved with the application of the microemulsion system.
Field examples are shown for fracture treatments of unconventional low permeability coals and shales, where water recovery and productivity are increased by 50% with the application of ME. A production analysis is presented for wells treated in the Barnett Shale that shows longer effective frac lengths and decreased damage surrounding the fracture.
Downhole Capillary Surfactant Injection System Pilot on Low Pressure Gas Wells in the San Juan Basin
Authors: McWilliams J. P. , Gonzales D. 
Published: December 2007

Abstract
Depletion of the reservoirs in the San Juan Basin is causing production rates to drop below the minimum lift critical velocity (MCV) in a large number of wells.Traditional methods used to address this issue include plunger lift, pumping units, foam lift, and re-circulation for wells with a compressor and tubing.With declining reservoir pressures, both plunger lift and re-circulation become less effective and often times the expense of a pumping unit, both to purchase and operate, cannot be economically supported by the well.In some cases, injecting surfactant may offer the most cost effective method of removing fluids.
To date, foam lift operations in the San Juan Basin have been accomplished by two methods.The most common method of applying surfactant to a well is dropping "soap sticks." This is very inexpensive but it demands a large amount of time from field personnel and can yield inconsistent production rates.The other common method of delivering surfactant to the well is through continuous injection of surfactant at the wellhead.The major problem with this method is that surfactant must drip down the annulus or tubing, which limits its effectiveness due to plating out on the wall surface.
The problems described above are eliminated through the use of a Downhole Capillary Surfactant Injection System (DCSIS).The DCSIS delivers surfactant directly to the bottom of the well bore where it is needed to be effective.A capillary stainless steel tubing string is run in the well bore and is attached to a fluid pump and a chemical storage tank.The capillary string can be run inside the tubing, outside the tubing, or down the slim hole production casing.Once installed, a metered amount of surfactant is injected down hole to help unload the well.
This paper discusses the results of a 10-well pilot of the DCSIS in the San Juan Basin.The pilot's objective was to determine the physical parameters necessary to estimate the MCV for foam flow and establish better criteria for selecting future installations.To accomplish these objectives, it was necessary to analyze the positive and negative responses to the installation of the DCSIS and determine the factors that led to each response.The data was then analyzed using statistical modeling tools to determine the most important factors affecting the response variable, percent increase in production (% uplift).This paper will discuss the results of a regression model that was built to determine the significance of several factors and to aid in the candidate selection process for future installations.Practical methods of determining the physical parameters necessary to generate foam flow will also be presented.
Casing Burst Strength After Casing Wear
Authors: Wu J. , Zhang M. G. 
Published: December 2007

Abstract
Casing wear by drillstring results in a thinner portion of casing wall and a reduction on casing burst strength (the ability to hold internal pressure). How to estimate the reduced casing burst strength on such a "crescent-worn" casing has been an important issue in oil and gas industry, as it is directly related to how to safely design casing strings. A common approach is to estimate the reduction of casing burst strength of such worn casing from API burst strength equation with a linear reduction by the remaining wall thickness or the wear percentage, equivalent to a "uniform-worn" casing model, despite a question on whether such a linear reduction of casing burst strength is over-conservative and may result in a higher casing cost.
This paper presents a further study on hoop stress and deformation of such a "crescent-worn" casing and discusses the reduction of casing burst strength. The hoop stress in the thinner portion of such a "crescent-worn" casing is found close to that from a "uniform-worn" casing, when local bending in the thinner portion of "crescent-worn" casing is ignored. The reduction of burst strength of casing worn by drillstring may still be estimated from casing yield or rupture burst strength with a linear reduction by wear percentage for sweet service well conditions, while more and non-linear reduction of burst strength of casing worn by drillstring may be needed for sour service well conditions, to prevent an "earlier" casing burst on sulfide stress cracking.
Extending Commercial Viability Through Near-Real-Time Cost Control and Operations Optimization
Authors: Doyle R. , Ippolito J. 
Published: December 2007

Abstract
Although conventional wisdom might suggest otherwise, mature fields represent a significant source of potential value. Operators can tap into this value by concentrating their efforts in three key areas: ensuring safe operations, minimizing operating costs, and maximizing current production. This paper examines specific instances in which fit-for-purpose work processes, technology, and training have been utilized to create value for operators of mature fields by optimizing safety programs, procurement processes, and other operations activities that affect each of the three key areas.
Horizontal-Well Productivity and Wellbore-Pressure Behavior Incorporating Wellbore Hydraulics
Authors: Anklam E. G. , Wiggins M. L. 
Published: December 2007

Abstract
Horizontal well performance is typically estimated using a steady-state productivity index equation similar to Joshi's productivity index, which assumes constant wellbore pressure. The wellbore pressure in a horizontal well is not constant, and the pressure drop in the horizontal section can approach the reservoir drawdown. This paper presents a new model to estimate horizontal well productivity by incorporating wellbore hydraulics. The model is implemented in a program and calculates the well pressure throughout the length of the wellbore. The method reproduces the experimental results of two authors.
A Look at Seabed Environmental Monitoring for Trinidad and Tobago's First Deepwater Drilling Campaign
Authors: Rajnauth J. , Boodoo C. , Dwarkah D. 
Published: December 2007

Abstract
Several dry-hole wells drilled during the period 1999 to 2003 was the outcome of deepwater drilling to date in Trinidad and Tobago. One of the objectives though of the deepwater drilling phase was to monitor the seabed to assess the fate and effects of discharged cuttings at the drill-site locations.
A monitoring plan was prepared by the operators to assess the amount, extent and effect of synthetic cuttings depositions. These effects include toxicity, water column effects and whether synthetic based muds bio-accumulate or biodegrade. Synthetic based mud is frequently used in deepwater drilling to assist in difficult drilling situations such as well bore stability, high temperatures and pressure, hydrate formation prevention and drilling time reduction. Computer model predictions were done on synthetic based mud cuttings deposition. The monitoring program includes video surveys, using sedimentary gauges and sedimentary traps.
The focus of this paper will be to look at and assess the monitoring plan, discuss the results from the monitoring surveys and compare with computer model predictions.
Controls On Soap Scale Formation, Including Naphthenate Soaps — Drivers and Mitigation
Authors: Turner M. S. , Smith P. C. 
Published: December 2007

Abstract
Soap deposits, which can manifest as emulsion soaps (carboxylates) or hard deposits (naphthenates), are an increasingly recognized cause of some unique flow assurance and crude marketing problems in oilfield processes. This paper illustrates the physical and chemical drivers for the generation of soap scales in a number of differing and challenging production system environments. Mitigation options for the successful treatment of soap scales are also discussed. Where possible, data presented in this paper are taken from field trials in order to illustrate these drivers and the impact of successful mitigation strategies.
An understanding of the key fluid characteristics allows pre-screening of fluids from new field developments that are likely to develop naphthenate/soap deposits and allows diagnosis of the likely soap scaling problems. The critical fluid characteristics required for the generation of naphthenate soaps are different from those required for generation of carboxylate soaps. An empirical approach to predicting the degree of risk for soap generation, based on oil and produced water properties, can be adopted, although there are knowledge and data gaps that increase the uncertainty of this approach.
Physical parameters, such as pressure, are known to influence soap generation. However, other physical parameters that are key in the design and operation of an oil-field process can also influence the soap severity. These parameters include temperature, shear, electrostatic fields, water cut and fluid-fluid incompatibility; examples of each are discussed. This information can be used in the design stages of an oil-field process where engineers must think beyond the conventional process designs.
Despite the fact that the impact of a soap problem can be considerably reduced by adjustment of physical design and operating parameters, chemicals are usually required to provide complete mitigation of soap. Chemical mitigation (acid and non-acid) guidelines are discussed with field examples and the need for a chemical management and monitoring programme.
Taking Coiled-Tubing Heave Compensation to the Next Level
Authors: Patton B. , Escobar J. C. , Schuurman R. , Mallalieu R. , Polsky Y. 
Published: December 2007

Abstract
As the number of deepwater installations increase, so will the number of coiled-tubing (CT) operations that are needed to support these deepwater fields. This need will grow significantly as rigs on spar platforms and tension leg platforms (TLP) are eventually demobilized for work on new installations, leaving CT as the most economical option for performing future well maintenance on these platforms.
The need to operate without a rig is a critical factor in the success of future coiled-tubing work in the deepwater environment. Rigless operation is complicated by the fact that each platform type has its own unique heave-compensation issues that must be addressed for an effective CT operation to take place.
An additional challenge to deepwater CT operations has been the assembly and installation of tension lift frames or heave-compensated jacking frames. This equipment is typically cumbersome and time-consuming to install and has many safety-related risks associated with the installation of coiled-tubing components.
A new coiled-tubing heave-compensation system has been created to address issues associated with rigging up and operating coiled tubing on deepwater installations. This system was designed with particular focus on operational safety and efficiency to meet the complete range of floating platform coiled-tubing deployment scenarios. There are three primary modes of operation. As a stand-alone system, it can operate as a heave-compensated jacking frame; with a rig, it can operate as a standard tension lift frame or as a self-compensating tension lift frame. The adaptive heave-compensation system uses automated process control to maintain wellhead loads within the American Petroleum Institute-specified allowable stress limits. A specially designed proprietary titanium flex joint incorporated in the system reduces the effect of lateral loads and bending moments transmitted to the wellhead.
The total heave-compensation package is composed of three skids (injector tension frame, blowout preventer (BOP) tension frame, and hydraulic power unit). The injector, gooseneck, and all well control equipment come preassembled within the injector and BOP tension frames. This improves the overall efficiency of the rig-up and eliminates most safety issues associated with the rig-up/rig-down process. The heave-compensation system not only improves the efficiency of the rig-up process but also makes tool changeouts more efficient.
The initial field test data and the associated job case history establish the benefit that this new heave-compensation system has brought to the deepwater market.
Predicting the location of barium sulfate scale formation in production systems
Authors: Collins I. R. 
Published: December 2007

Abstract
Mineral scale formation and deposition on downhole and surface equipment is a major source of cost and reduced production to the oil industry. This paper describes a novel semi-quantitative kinetic approach to predicting the location of barium sulfate formation and deposition. The key conclusions of this work are: There is probably negligible formation damage arising from barium sulfate deposition in the near well bore region.There are three kinds of barium sulfate precipitation in the well depending upon the scaling tendency (saturation ratio) in the produced brine (it is assumed that the higher saturation ratio values for barite at the bottom of the well is a consequence of mixing of high sulfate brine from sea water breakthrough with high barium brine formation water). The location of the scale formation can be predicted from knowledge of the nucleation induction time coupled with mass transfer arguments. The equations describing these have been developed in this paper and applied to some general illustrative cases demonstrating the applicability of the approach. In particular, a method has been developed for predicting the location of scale formation and deposition at low saturation ratios such as developed when sulfate-removal is utilized as a barite scale control technology.
Quantifying Greenhouse Gas Emission Reductions from Enhanced Oil Recovery Operations
Authors: Loreti C. P. , Grygar W. W. 
Published: December 2007

Abstract
Enhanced oil recovery (EOR) has been identified as a promising way of sequestering carbon dioxide (CO2). When CO2 that would otherwise be vented to the atmosphere is used in the process, the CO2 remaining in the ground represents a reduction in greenhouse gas (GHG) emissions.
The accurate quantification of the amount of CO2 sequestered is important as companies look to market the emission reductions associated with EOR operations. Purchasers of emission reductions need assurance that the reductions they are purchasing are real. Often, however, losses of CO2 and methane (CH4) during the operation of EOR projects are not fully considered in accounting for the emission reductions. While minor fugitive losses of CO2 may be accounted for, much larger losses that may occur as a result of the way equipment is configured or how facilities are operated are often ignored.
This paper presents a methodology for quantifying the net greenhouse GHG emission reductions resulting from enhanced oil recovery operations based on the observation of a range of operating facilities. It demonstrates the need to consider the operational aspects of the production facilities in quantifying the amount of GHG emission reductions. It concludes that losses of CO2 and CH4 in EOR operations may be large enough that unless they are fully considered, the magnitude of any claimed emission reductions may be subject to question.
Increased Access to Federal Lands through Data Sharing
Authors: Belieu S. D. , Jehn P. J. , Bohrer M. F. 
Published: December 2007

Abstract
Much of the environmental and technical data useful to the oil and gas industry and regulatory agencies is now contained in disparate state and federal databases. Delays in coordinating permit approvals between federal and state agencies translate into increased operational costs and stresses for the oil and gas industry. Making federal lease stipulation and area restriction data available on state agency Web sites will streamline a potential lessors review of available leases, encourage more active bidding on unleased federal lands, and give third-party operators independent access to data who otherwise may not have access to lease restrictions and other environmental data.
As a requirement of the Energy Policy Conservation Act (EPCA), the Bureau of Land Management (BLM) is in the process of inventorying oil and natural gas resources beneath onshore federal lands and the extent and nature of any stipulation, restrictions, or impediments to the development of these resources.
The EPCA Phase 1 Inventory resulted in a collection of GIS coverage files organized according to numerous lease stipulation reference codes. Meanwhile, state agencies also collect millions of data elements concerning oil and gas operations. Much of the oil and gas data nationwide is catalogued in the Ground Water Protection Council's (GWPC's) successfully completed Risk Based Data Management System (RBDMS).
The GWPC and the states of Colorado, New Mexico, Utah, and Montana are implementing a pilot project where BLM lease stipulation data and RBDMS data will be displayed in a GIS format on the Internet. This increased access to data will increase bid activity, help expedite permitting, and encourage exploration on federal lands.
Linking environmental, lease stipulation, and resource inventory assessment data and making a GIS interface for the data available to industry and other agencies via the internet represents an important step in the GWPC strategy for all oil and gas regulatory e-commerce. The next step beyond mere data sharing for facilitating the permitting process is to make it possible for industry to file those permit applications electronically. This process will involve the use of common XML schemas.
This paper describes the coordinated effort being undertaken by the member states of GWPC, BLM, POSC (Petrotechnical Open Standards Consortium), MMS (Mineral Management Service), and others to make this effort a reality.
Optimize Separator Operating Pressures to Reduce Flash Losses
Authors: Boyer B. E. , O'Connell S. C. 
Published: December 2007

Abstract
Flashing losses from crude oil and condensate storage are routinely vented to the atmosphere. By minimizing operating pressure of low-pressure separators, the amount of flashing losses can be reduced, resulting in increased profits at a minimal cost of implementation and an immediate payback. Companies can be report these methane reductions to the Environmental Protection Agency's Natural Gas STAR Program. Devon Energy realized savings of approximately $7000 per year after separator optimization at one of its oil and gas production facilities.