bluuebunny/crossref_metadata_2025_split huggingface dataset:
Material Balance Analysis of Faulted and Stratified, Tight Gas Reservoirs
Authors: Hagoort Jacques , Sinke Jaap , Dros Barry , Nieuwland Ferry 
Published: December 2007

Abstract
P/Z plots of tight gas reservoirs based on non-extrapolated pressures are generally curved and can deviate strongly from the theoretical straight line. Interpretation of these plots by the conventional straight-line method may significantly underestimate GIIP. The paper presents and explains the p/z behavior of tight gas reservoirs for a number of simple prototype reservoirs. It is shown that in many cases the curved p/z plots can still be interpreted quantitatively. The key to the interpretation is the concept of semi-steady-state time. Even if no quantitative interpretation is possible, a p/z plot is still a powerful diagnostic tool. When p/z plots can not be analyzed quantitatively, one has to resort to history matching of shut-in bottomhole pressures and of continuously measured wellhead pressures by using a numerical reservoir simulator.
The Reliability of Core Data as Input to Seismic Reservoir Monitoring Studies
Authors: Nes O. -M. , Holt R. M. , Fjær E. 
Published: December 2007

Abstract
There is a potential for improving the reliability of standard core tests for seismic monitoring studies. A primary concern is to quantify and correct for core damage effects, which significantly enhance the stress dependency of wave velocities. Careful laboratory procedures and modeling efforts may reduce such effects. However, no simple procedure is currently available to eliminate this problem. The use of simplified laboratory test procedures, in particular application of an inappropriate effective stress principle, may lead to erroneous interpretations.
Towards a Mono-Diameter Well – Advances in Expanding Tubing Technology
Authors: Benzie Scott , Burge Phil , Dobson Andrew 
Published: December 2007

Abstract
Solid steel tube can be readily expanded using forces, either mechanical or hydraulic available on most drilling and workover rigs. The process of drawing or pumping a mandrel through a length of tube can be used to expand the tube in situ. This process can be used to repair casing and tubing, shut off unwanted fluid entry into, and egress from the wellbore, repair sand screens, and act as a contingency liner in drilling applications. The ultimate use of expanded tubulars will be in the mono-diameter well, whereby the entire well is drilled and cased using effectively one hole size. The impact on drilling costs and performance will be dramatic.
Expandable tubing technology has been applied in the three market segments of remediation, wellbore construction and sand control. A broad range of products is currently available for implementation in all three segments. A review of the principles of expandable tubing technology leads to a discussion of the likely evolution of the technology towards the monodiameter well. The implementation of expandable tubing will follow a pattern of replacement of conventional technologies, use through necessity, maintenance of diametric efficiency which will lead to the use of the technology within the basis of design of well construction. From this is but a small step to the monodiameter well.
The principles of expandable tubing technology are well understood. The complexity arises from the system interactions between the materials, expansion process and the wellbore environment. These are explained and discussed.
Economics And Design Of Offshore Safety Systems
Authors: Stokley Charles O. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Introduction
Safety systems for offshore producing facilities are presently installed as required by government regulations. A less frequently considered aspect is that of safety systems as justifiable investments. A logical economic analysis may be performed to demonstrate that these systems are in fact valid economic decisions. The analysis compares with an accidental-death type of life insurance policy, whereas the system is a low-dollar investment for protection of a potentially larger expense in case of a catastrophe.
Several design considerations to enhance the economics through a reduction of maintenance costs and improved reliability are discussed also.

ECONOMICS
The following simplified formula provides a logical method for estimating the risk weighted cost of a catastrophe. This method could be related to a single piece of equipment as well as the entire facility, as will be shown in the two examples.
Using this general formula, two cases will be examined.

Case I
Area: Offshore California, 1,000-ft water depth, 20 producing wells to a total depth of 6,000 ft, at a total platform cost of $100 million.
Production: 20,000 BOPD at $8.00 per bbl and 20 MMcf/D at $1.00 per Mcf with a straight line decline for 20 years.
Problem: Major fire catastrophe, one well uncontrolled flow and fire.

C Estimate:
F = 0.006 three accidents per 500facilities each 5 years PV = $145,000 fifth-year rate of 16,000 PV = $145,000 fifth-year rate of 16,000 BOPD and 17 MMcf/DT = 40 days rig on location in 10 days;30 days to drill and control T = 210 days 60 days to secure; 150 days to repair and test PV = $15.2 M 40 days open flow one well PV = $15.2 M 40 days open flow one well plus 2 percent reserve losses
A Diverless Subsea Drilling And Completion System
Authors: Page John 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
The Petroleum Industry has ventured farther and farther offshore into deeper-and deeper waters exploring for needed hydrocarbons to meet increasing world energy demands and to replenish dwindling known oil and gas supplies. Since installation of their first subsea well completion system in 1962, Vetco has continued to engineer, develop, and manufacture subsea equipment to meet the increasing demands of this hostile environment. This paper describes a completely remote and diverless type of subsea drilling and completion system which has been developed, using field-proven principles and equipment. A 15-minute movie which records the actual installation of this subsea system in the Gulf of Mexico during 1976 is part of this presentation. The film, which was basically developed for training purposes, describes the general procedures and equipment used for this type of procedures and equipment used for this type of installation.

Introduction
Offshore oil and gas fields have, for many years, been produced from fixed platforms of various sizes which have been installed on the ocean floor and which become the base for directionally drilling of development wells. Land production equipment is used and the produced oil production equipment is used and the produced oil or gas is flowed or pumped to an offshore producing terminal or shore-based production producing terminal or shore-based production facility. The number of wells drilled and produced from a fixed platform varies considerably, depth and productivity being the criteria.
Until recently, water depths in which platforms were installed ranged from only a few feet to about 450 feet. Presently, however, with the technology available to the industry, these depths have been increased and platforms are being installed in deeper and deeper waters; one major company is planning to install a fixed platform in 1,000 feet of water off the Louisiana platform in 1,000 feet of water off the Louisiana coast. To date, however, the greatest depth at which a platform has been installed is 850 feet (in the Santa Barbara Channel).
During this and similar operations it became obvious that there was a depth at which it was technologically more difficult and economically improvident to consider fixed platforms, and other methods of production had to be investigated. Considerable time and effort was devoted to this problem; and, of the many ideas proposed, one of the more successful has been the single subsea wellhead completion system.
Evaluation And Control Of Sand Production In Gas Wells
Authors: Anand Jeevan 
Published: December 2007

Abstract
One of the major problems encountered in high deliverability gas wells is sand production from the formation and resultant erosion of subsurface and surface facilities. Because of extremely high velocities, even a small amount of sand for a very short duration can result in complete erosion of steel pipe at critical areas.
A testing program was carried out at Aliso Canyon Gas Storage Field in January-May 1976, with the following objectives:Quantify the steel erosion rate due to sand production for each well at different production rates.Project gas production rates at various reservoir pressures with an acceptable steel erosion rate.Evaluate different kinds of bottomhole completions with regard to their effectiveness in controlling sand production.
Specially designed steel probes were used in gas flow stream and their weight loss during the test was related to annual erosion loss of the steel pipes. Production rates were predicted based on constant sand face predicted based on constant sand face velocity at various reservoir pressures and found to be safe. A pressures and found to be safe. A critical review of the test data showed that bottomhole completions designed specifically to control sand production can substantially increase sand production can substantially increase sand free gas deliverability.

Introduction
Before an oil or gas field is acquired for gas storage purposes, testing is usually done to evaluate characteristics of the reservoir rock. Porosity, permeability and liquid saturation Porosity, permeability and liquid saturation are commonly determined, but sand production tendencies are rarely evaluated. production tendencies are rarely evaluated. This was the case when Southern California Gas Company acquired the Aliso Canyon Field for gas storage. Existing wells had been completed with both slotted liners and perforated casing.
Research on Hydrophobically Associating Water-Soluble Polymer Used for EOR
Authors: Yabin Niu , Jian Ouyang , Zhuoyan Zhu , Guijiang Wang , Guanghua Sun , Lijun Shi 
Published: December 2007

Abstract
On the base of molecular structure design, we have synthesized hydrophobically associating water-soluble polymers. The solution properties of hydrophobically associating water-soluble polymer as a function of electrolytes concentration temperature and shear rate have been investigated. The enhance in oil recovery obtained in core flow experiment with the polymers solution is higher. This polymer is developed for use under hostile reservoir conditions.
Study of Corrosion Control Effect of H2S Scavengers in Multiphase Systems
Authors: Tung Nguyen Phuong , Hung Pham Viet , Tien Hoang Dinh , Loi Cao My 
Published: December 2007

Abstract
Aggravated corrosion conditions caused by H2S in mixture of oil, brine and gas are responsible for some of the highest equipment failure rates in the petroleum industry. Thw sulfide scavengers HP1 and HP2 have been developed to protect well equipment and pipeline steel from sulfite cracking, electrochemical corrosion and corrosion fatigue. The desulfurisation efficiency and corrosion inhibition rate of scavengers in multiphase systems were measured in the laboratory. Their desulfurisation efficiency exceeded 90% and the corrosion inhibition rate was up to 98%.
Based on the obtained results, the scavengers HP1 and HP2 can be recommended for field test and field application as well.
Electromagnetic Propagation ... A New Dimension In Logging
Authors: Calvert Thomas J. , Wells Larry E. 
Published: December 2007

Abstract
One of the primary requirements of well logging is the ability to distinguish between oil and water. Resistivity/Conductivity and pulsed-neutron tools can do it if the water is fairly saline, and if its salinity is known. However, a method has long been needed that is less dependent upon knowledge of water salinity. Schlumberger's new Electromagnetic Propagation Tool measures the phase shift and attenuation of microwave-frequency energy propagated through the formation near the borehole. From these measurements, it is possible to derive values of porosity and water saturation that are practically porosity and water saturation that are practically independent of water salinity, except in ranges close to saturation. Notable is the fact that the new tool is most accurate in fresh waters, an area that has been troublesome. An experimental tool has been in the field for many months, running logs in eight states and a Canadian province. Field test results have exceeded expectations, and equipment is being built for commercial service. This paper gives the operating principles of the tool, describes the interpretation method that has been developed, and presents several field examples to illustrate the importance of this new logging measurement.
Using Neural Networks for Prediction of Formation Fracture Gradient
Authors: Sadiq T. , Nashawi I. S. 
Published: December 2007

Abstract
Accurate formation fracture gradient prediction is an essential part of well planning. Erroneous fracture gradient estimates may jeopardize the entire drilling operation and result in serious well problems, the least of which are lost circulation and kick leading to blowout. Accurate fracture gradient values play an important role in the selection of proper casing seats, prevention of lost circulation and planning of hydraulic fracturing for the purpose of increasing well productivity in zones of low permeability. Furthermore, a good knowledge of the fracture gradient is of great importance in areas where selective production and injection is practiced. In such areas the adjacent reservoirs consist of several sequences of dense and porous zones such that, if a fracture is initiated during drilling or stimulation, it can propagate and extend, establishing communication between hydrocarbon reservoirs and can extend to a nearby water-bearing formation.
Fracture gradient depends upon several factors including magnitude of overburden stress, formation stress within the area and formation pore pressure. Any prediction method should incorporate most of the above factors for a realistic prediction of the fracture gradient.
This paper presents an artificial neural network model that yields reasonably accurate values of the fracture gradient. The input training data are actual field data. The results obtained from the model are compared with those obtained from correlation. The comparison shows that the method is promising and under some circumstances it is superior to the available techniques.
Application of Hydraulic Fractures in Openhole Horizontal Wells
Authors: Ellis P. D. , Kniffin G. M. , Harkrider J. D. 
Published: December 2007

Abstract
This paper describes a process that has improved production, reduced costs, saved time, and dramatically improved the results of fracture stimulating low permeability horizontal wells. The use of both propped and acid fracture treatments will be described.
The process has been used for openhole completions aligned in the approximate direction of fracture propagation as well as for fractures transverse to the well bore. The technique has effectively eliminated well bore connectivity problems that had been observed in vertical completions and cased and cemented horizontal wells with transverse fractures.
The process has been used to increase production over 25 fold in a 30 year old field. It has also proven successful in a marginally economic field that had been completed using propped fractures in vertical wells.
The procedure employs a system of multiple, retrievable treating subs that are specifically tailored to a unique well bore configuration and allow treating the entire interval with a single stage. The treating subs are designed to distribute the treating fluid as desired along the length of the lateral. The process has been successfully used in over 100 wells and laterals in fields located in California, Illinois, New Mexico, Utah, and Texas.
Material-Balance Method for Production Rejuvenation With Horizontal Wells
Authors: Hsieh Frank S. , Kandel Philip S. , Vega Cecilia 
Published: December 2007

Abstract
Material balance evaluation can be conducted at every stage of reservoir development, including production rejuvenation using horizontal wells. Material balance evaluation for a reservoir with water influx usually begins with the calculation of water influx quantities using aquifer models (the aquifer model approach). The calculated influx quantities are substituted into material balance equations that are arranged in straight-line formats. Should a linear slope be found, the original-hydrocarbons-in-place is the y-intercept. The key to a successful evaluation using the aquifer model approach lies in the selection of a representative aquifer model. Selecting a representative aquifer model is difficult due to reservoir uncertainties such as rock properties, and the size, geometry, and continuity of the aquifer. Also, influx calculations using the aquifer model approach are time-consuming because they usually require a trial and error method of solution.
This paper presents a material balance equation in a form that allows for calculating water influx without the use of an aquifer model. This approach has many applications and is particularly useful for production rejuvenation projects, such as the drilling of horizontal wells.
Performance of Horizontal Wells in Gas-Condensate Reservoirs, Djebel Bissa Field, Algeria
Authors: Dehane A. , Algeria D. Tiab , Osisanya S. O. 
Published: December 2007

Abstract
Properties of gas-condensate reservoirs are particularly difficult to study due to the composition and phase changes of light components that occur during the reservoir depletion. At the first stage of their discovery, these reservoirs behave like gas reservoirs during depletion. Once the dew point pressure is reached at reservoir conditions of pressure and temperature a retrograde condensation phase develops in the reservoir. Liquid condensation in the formation can result in severe loss of well deliverability and therefore of gas and condensate recovery, which will certainly lead to a loss of income.
In this study, the performance of horizontal wells and vertical wells in gas condensate reservoirs is investigated under various depletion schemes. The expected low drawdown pressure for horizontal well, compared to vertical well for the same flow rate, considerably reduces retrograde condensation. A reservoir simulator is used to compare liquid saturation profiles for horizontal and vertical wells in gas condensate reservoirs. The influence of the horizontal well length section and reservoir thickness on horizontal well productivity, and condensate recovery were also studied. Another factor investigated in this study is the effect of drilling a horizontal well in a gas condensate reservoir that has already been developed by vertical wells.
To illustrate the productivity increase due to the use of horizontal wells in gas condensate reservoirs, Djebel Bissa field (Figs. 1 and 2) data are presented and discussed using a compositional single well model (VIP simulator). The main results of this investigation are as follows: A smaller pressure drawdown for a horizontal well compared to that of a vertical well, eliminates or reduces liquid condensation in the reservoir.
Layers with higher capacity (kh) values contain the most liquid accumulations.
A Numerical Model Coupling Reservoir and Horizontal Well Flow Dynamics: Transient Behavior of Single-Phase Liquid and Gas Flow
Authors: Vicente R. , Sarica C. , Ertekin T. 
Published: December 2007

Abstract
A fully implicit, three-dimensional simulator with local refinement around the wellbore is developed to solve reservoir and horizontal well flow equations simultaneously, for single-phase liquid and gas cases. The model consists of conservation of mass and Darcy’s law in the reservoir, and mass and momentum conservation in the wellbore for isothermal conditions. The coupling requeriments are satisfied by preserving the continuity of pressure and mass balance at the sandface. The proposed simulator is tested against and verified with the results obtained from a commercial code ECLIPSE-100™, and available public domain simulators and semi-analytical models.
The model can be used to simulate the transient pressure and flow rate behavior of both the reservoir and the horizontal wellbore. Traditional decoupling of the wellbore transients from the reservoir transients does not capture the horizontal well pressure and flow rate transients at early times since the interaction between the reservoir and wellbore is inherently neglected. Simulation runs with the proposed model reveal the actual characteristics of horizontal wellbore storage and unloading. The effects of permeability, formation thickness, well length, and fluid compressibility are also studied.
Sand Production Prediction for Horizontal Wells in Gas Storage Reservoirs
Authors: McLellan P. J. , Hawkes C. D. , Read R. S. 
Published: December 2007

Abstract
Sand production and the sand control technique selected to mitigate or eliminate it can have a critical influence on the performance of horizontal wells in gas storage reservoirs. A completion that provides adequate sand control is usually required, but an overly conservative completion design can have an unnecessary, negative consequence on gas well productivity and injectivity. The selection of the appropriate sand control design depends on the characteristics of the reservoir formation, the in-situ stress state, the maximum and minimum values of the reservoir pressure during gas storage operations, the drawdown pressure, the near-well fluid saturations, the well trajectory and the capacity for handling sand in the well tubulars and surface facilities.
This paper reviews the principal causes of sand production from borehole and perforation collapse, and demonstrates the application of commercial software programs for assessing sand production risks. The influence of formation damage, compressible and non-Darcy gas flow effects, reservoir pressure changes and rock strength reduction due to cyclic loading will be illustrated. Additional risks, such as exceeding the fracture breakdown pressure in the reservoir during injection, or collapsing weak, interbedded shale strata that are locally penetrated by the horizontal well, are also described. Numerical geomechanical modelling techniques suitable for more complex material behaviour and fluid flow phenomena are also described, as well as a novel procedure for estimating initial produced sand volumes.
Several field examples are presented, illustrating results for reservoirs ranging from relatively strong rocks, in which no sand control is required, to poorly cemented sandstones which require gravel-packed or screened completions.