bluuebunny/crossref_metadata_2025_split huggingface dataset:
Integrated Horizontal Well Stability Design in Potiguar Basin
Authors: Ferreira F.H. , Siqueira C.A.M. , Martins J.A.S. 
Published: December 2007

Abstract
Problems related to wellbore stability can increase drilling and completion costs. At the limit it can be impossible to drill a well because of wellbore mechanical instability. Several wellbore stability simulators can be found in the literature. Some of them present very simplified analytical solutions while others are numerically complex. Besides choosing the simulator, it is necessary to know the elastic and strength properties of the rock, the in-situ stress field, rock porosity and permeability and original pore pressure. Determination of some of these input data are costly and sometimes impossible. This paper presents the data gathering and design of a horizontal well in the Potiguar Basin (fig. 1) in Northeast Brazil. The main goal of this work is the determination of the mud density to drill a horizontal well, safely and economically viable, in order to avoid wellbore collapse (inferior limit) and formation breakdown (superior limit).

Introduction
This paper presents an integrated wellbore stability design for drilling a horizontal well in the Potiguar Basin. An integrated wellbore stability analysis means data gathering and mechanical stability numerical simulation.
Underground rocks are always under a compressive stress field. When drilling a well, an amount of material is removed and consequently the wellbore neighborhood needs to support the load that was supported by the removed material. This new stress state may cause the wellbore rupture depending on the mud density and formation strength parameters.
Rock behavior is totally different if it is submitted to compressive or tensile loading. Because of this, it is necessary to consider two different failure criteria to properly represent rock collapse behavior (compressive stress state) and another to represent formation breakdown (tensile stress state). These two criteria are presented in Appendix A.
Field data and lab tests have provided the in-situ stress field and rock mechanical properties for the horizontal well stability analysis presented in this paper.
Fracture propagation and pressure decline were analyzed from step rate test (SRT) allowing the stress field evaluation. Unfortunately a minifrac was not scheduled for this field. Elastic and strength parameters were determined from triaxial (drained) and uniaxial compressive tests done by Rock Mechanics Laboratory at Petrobras Research Center (CENPES).
Fluid properties, rock porosity and permeability, were obtained through lab tests. The bottom hole static pressure was determined in field.
A Finite Element Method (FEM) simulator (AEEPECD) was developed at CENPES for mechanical stability analysis in plane strain problems - The material constitutive law was considered elastic-plastic. MTOOL and MVIEW were used as pre and post-processors, respectively.
ESP's In Cyclic Steam Injection Wells
Authors: Gonzalez R. , Brunings C. , Toussaint L. 
Published: December 2007

Abstract
Since 1993, Electrical Submergible Pumps (ESPs have been applied with excellent results in the cold production of heavy crudes (9.5 API) in about 70 horizontal wells in the hamaca area of the Orinoco Faja. Over the three year production life of these wells, production declinations due to natural and mechanical causes of up to 50 % have been observed.
As an alternative to increase the production to the original rate of around 1500 bpd, cyclical steam injection in conjunction with the ESPs has been proposed. This process will entail periodic injection of steam in vertical or deviated wells in the same reservoir as the horizontal wells in order to evaluate the performance of ESPs in the high temperature environment. This test will be conducted in the latter part of 1996 with the intention of applying the results to the horizontal wells during the fiscal year 1997.
The evaluation will be realized as a joint effort between CORPOVEN and CENTRILIFT as a part of their strategic alliance which is now in operation.
The technical paper will show the ESP designs, the evaluation program, and the results, while comparing the production rates and costs of cold vs. thermal production methods.

Introduction
Heavy and extraheavy crude oil has traditionally. been produced in both cold and hot production (cyclic steam infection) with pumping units as the artificial lift method These pumping units have been replaced in part by electrical submersible pumps. (ESPS) Initially its application was in horizontal wells in the Orinoco Belt extending this system to the traditional areas of heavy oil. Right now, there are more than eighty wells producing more than 50,000 bpd in cold production with ESPS.
The outcome obtained with the application of ESPS have been excellent. Rates per well of over 2,500 bpd (16.6 m3 /h) of 9.1 API of crude oil have been recorded; however, some of the horizontal wells did not perform as expected, due to formation damage caused by drilling fluids during the completion of the wells.
As a result, the action taken was to stimulate these low productivity wells. The first stimulations were chemical (HCL), getting initially good results by increasing the production of the well from 150–200 bpd (0.99–1.32 m3 /h) to 800 bpd (5.29m3 /h). This production lasted one to two months. The other stimulation applied was thermal (cyclic steam stimulation); the first test was made in the well FBA 18 from the Bare field of the Orinoco Belt. This well incremented its production from 150 bpd (0.99 m3 /h) to 900 bpd (5.96 m3 /h), keeping the same rate for four months (until the writing of this paper). This well started to produce with an ESP system and continued to produce with the same method specially suited for thermal operations.
Evaluation of Completion Techniques in Salem Formation Using Real Data Fracturing Analysis
Authors: Holekamp S. , Payne M.E. , Albi J.T. 
Published: December 2007

Abstract
Completion strategies and stimulation design are both vital to the performance of an oil well. In most cases these two are optimized, however, in many cases this is done separately. There are clear advantages to developing a completion strategy that includes the stimulation design. When the stimulation design is viewed as a "contingency plan" if the original completion strategy fails or is not optimized, the original completion can severely limit the stimulation design.
Real time diagnostics are used to evaluate two scenarios and compare only one of many issues relating to completion strategies and stimulation design.

Introduction
Two similar wells in the Salem Formation were fractured using pretreatment diagnostics to aid in treatment design. Well No. 1 was produced for 3 1/2-years prior to fracture treatment recovering a total of 9400 bbl of oil. Well No. 2 was completed and fractured prior to any production. Included are results of prefracture diagnostics in both cases and production history of both cases. The purpose of this paper is to evaluate completion strategy, job size, and treatment diagnostic techniques in this field considering the production, pretreatment diagnostics, and treatment execution.
It is an agreed upon fact that the single most influential factor in fracture growth is the stress profile of the reservoir. This stress profile is influenced by the properties of the rock and of the pore fluids. The rock properties cannot be significantly effected, however, we can effect the pore fluid properties. The well can be produced to reduce the pore fluid pressure hence reducing the effective stress on the rock. Depending on the porosity, permeability, and the changes of these parameters with depth this process can drastically change fracture growth behavior.

Discussion of Results
Well No. 1. The first well treated was produced for 3 1/2-years prior to Fracture treatment recovering a total of 9400 bbl of oil. The reservoir pressure was reduced from 800 to 650 psi. This reduction in pressure should have created an additional 78 psi stress contrast between the productive layer and the boundary layers. The response of the prefrac treatment in this case was almost "textbook." A very clear closure could be seen and the decline was indicative of a contained fracture with leakoff characteristics of a classic wall building fluid. A forward simulation was run based on the diagnostic tests and the pump schedule was revised and pumped. P. 17^
A Study of the Above Average Waterflood Recovery of the Richardson Berea Field, Calhoun and Roane Cos., West Virginia
Authors: Blomberg John R. 
Published: December 2007

Abstract
A conventional waterflood of the Richardson Berea sandstone will yield a much greater than forecasted oil recovery. The very low permeability upper portion of the sandstone was ever considered pay but obviously a large portion of the recovery in the waterflood came from this "non-pay". Similar situations may exist in other oil fields, especially old or lugged oil fields that may present economical future development potential.
Integrated Footage Contract Vs. Day Rate; Drilling Time and Cost Analysis
Authors: Jabbar A. , Saifaldeen M. , Thabet Sayed Abdul Rahman 
Published: December 2007

Abstract
In 1993, Qatar General Petroleum Corporation (QGPC) conducted a comprehensive review of its Offshore drilling operations and cost under the then existing day rate contracts for the three offshore jack-up rigs under hire. The results of the study indicated that substantial cost saving could be achieved through the implementation of integrated footage contracts, such that most of the hole sections are drilled under footage; giving the rig contractor footage incentives to drill vertical and deviated hole sections. Similar "integrated" footage contracts had been successfully employed by QGPC in their onshore operations (vertical wells) for several years.
In August 1994, the first integrated footage contract for Offshore Operations was implemented. Some 25 wells have been drilled and side-tracked under integrated footage contracts since. Following the success of the first footage contract, two subsequent additional jack-up rig contracts were awarded on a similar contract strategy.
The paper focuses mainly on the differences in rig charges, intangible drilling cost and overall drilling performance under the integrated and day work contracts, as most of the tangible cost have remained relatively constant.
Assessment of Application of Dynamic Kill for the Control of Middle-East Surface Blowouts
Authors: Al-Shehri Dhafer A. 
Published: December 2007

Abstract
This paper presents some results from research work1. The purpose of this work was to investigate and assess the potential of dynamic kill as a method for controlling blowouts from producing gas and oil wells. Only scattered and little previous work was done on dynamic kill, particularly in the areas of gas kicks and blowouts during drilling. Blowouts of oil and gas wells after completion and starting production have received much less investigation.
In this work, a new dynamic kill model was developed for controlling surface induced blowouts of oil and gas wells. The model simulates multiphase flow in a blowout and relief wells. Dynamic simulation is performed for both kill through a relief well and through in-well surface injection.
The simulator makes use of proven multiphase flow models. Several assumptions and improvements are added or included in these models to account for flow geometry, temperature variation in the flow conduits and the effect of sonic flow closer to the surface.
The simulator predicts and links the expected reservoir performance with wellbore hydraulics. The effects of introducing the kill fluid into the well stream are also simulated.
Relief well dynamic kill simulations can predict the minimum injection flow rate into the relief and blowout wells, initial and final kill fluid densities, size and type of drilling string requirement for achieving the required kill rate(s) in the relief well(s), and horse power requirements. Simulations can also check for ability to inject at the desired rate through the formation. In the case of in-well kill, the model can be used to determine the optimum location of the point of kill fluid injection.
The model results were in agreement with data presented in the literature and from Kuwait field measurements.
The simulator leads to a much better level of understanding of blowout behavior and the potential of dynamic kill to bring gas and oil blowouts under control.
Kuwait Post-Capping: The Return to Production
Authors: Ali-Hussain A. , Drury G. J. 
Published: December 2007

Abstract
The recovery of oil production in Kuwait following Liberation required the tremendous efforts of many people. With regards to the oilfields, the initial phase of the recovery process was to shut-off all of the blowouts. This task was on a scale far beyond any other that the industry had ever seen. Specialized firefighting teams composed of both local KOC employees and Industry experts from around the world were assembled to tackle the huge task. These firefighting teams received much attention as the world watched their progress to control an event that impacted the environment of many nations However, following the successful completion of the firefighting teams there remained the second phase. This phase consisted of the monumental task of returning the oilfields to production. The efforts and accomplishments of this phase are not widely known It is the focus of this paper to highlight the various techniques incorporated to salvage the damaged wellheads and casing strings and where possible return these wells to production. This work will include the broad range of well types that are present within Kuwait, ranging from low pressure to high pressure (15M psi) completions. Additionally, the work consisted of various phases which included both rig and rig-less operations It should be highlighted that the damage to each well was unique with some wells requiring only minor repairs to the extensively damaged wells which required wellhead removal, splicing of casing strings, fishing operations, and recompletion. To further complicate the process, the work was conducted in an environment that was less than optimum with the presence of H2S. extreme desert temperatures, oil-ladcn soil, and unclcarcd minefields This work is equaled only by the tremendous accomplishments of the initial firefighting phase.
Mode Localization May Explain Some of BHA Failures
Authors: Yigit A. S. , Al-Ansary M. D. , Khalid M. 
Published: December 2007

Abstract
A Finite Element Model is developed for investigating the BHA dynamics. The stabilizers, WOB, and gravity effects are considered. The natural frequencies as well as the mode shapes are obtained through modal analysis. The results show that in certain drillstring configurations a small amount of parameter variation (disorder) may cause what is known in structural dynamics literature as "mode localization". If the modes are localized, vibrational energy is confined to small geometric regions instead of being propagated. This in turn results in very large amplitudes at certain locations which are not predictable through analysis of the nominal system. A field case is used to demonstrate the occurrence of this phenomenon under realistic conditions. Several operational and design methods to avoid the occurrence of mode localization are suggested.
The Drilling Optimization Performance in Kuwait's High Pressured Wells
Authors: Al-Sarraf Adel , Hazel Richard A. 
Published: December 2007

Abstract
Since the spudding of the first well in the Burgan Field in 1937, continuous improvements have been made in the drilling of wells in Kuwait. This paper will address the drilling optimization performance that has occurred during the development of the deeper high pressured formations.
Continued optimization performance in the deeper high pressured wells has proved to be the greatest challenge as a result of the adverse geological environment that has had to be addressed while drilling. This adverse geological environment consists of salt/anhydrite sections where formation pressure nearly equals fracture strength, pressure reversals, highly fractured thief zones and the presence of H2S.
While there was some earlier deep drilling in Kuwait, development of the deeper high pressured horizons began in earnest in the early to mid 80's and is still ongoing. Four major field studies will be addressed in the paper which encompasses the majority of the deeper high pressure drilling activity. The inherent problems that had to be overcome, the solutions that were found and the problems still to be faced will be depicted in this paper.
Abduliyah Field drilling has improved by a reduction of 77% in drilling days over a 12 year period. Magwa Field drilling has improved by a reduction of 58% in drilling days over a 10 year period. Minagish Field drilling has improved by a reduction of 74% in drilling days over a 14 year period. Umm Gudair Field drilling has improved drilling by a reduction of 72% in drilling days over a 13 year period. Total well depths for the above fields has ranged from 11800' to 16800’
Improvements which will be detailed in this paper will include well design changes, methods dealing with lost returns, mud cap drilling, bit optimization, and others.
7" Monobore Completion Design for Qatar's Offshore North Field
Authors: Martin Ben L. 
Published: December 2007

Abstract
Producing gas from the Khuff formation in Qatar's offshore North Field presents several completion design challenges. The North Field Khuff formation is a competent limestone / dolomite that is estimated to contain a GIIP of 504 x 1012 scf (504 TCF), which makes it the largest single accumulation of natural gas in the world. The North Field Khuff gas contains hydrogen sulfide and carbon dioxide concentrations of approximately 5,000 ppm and 2.5 mole percent, respectively. Initial condensate yields exceed 40 bbl/MMscf. For design purposes, brine water production was taken into account when making the metallurgical choices for the completion equipment. The producing interval, Khuff K-4 at a datum of 9,400 ft. subsea has a bottom hole temperature of 222°F, and an initial shut-in bottom hole pressure of 5,265 psi. Actual well deviations range from vertical to slightly over 60° from vertical, but all completion equipment was designed and tested to function properly in horizontal wells. The monobore completions have also been designed to accommodate high rate and high volume HCI acid stimulations that are performed during initial completions, and that may be needed throughout the life of the field.
Qatar's North Field monobore completions have been designed to accommodate all of the above well conditions under all expected wellbore load cases, while providing years of trouble free service.
This paper describes the wellbore and equipment design concepts utilized, the equipment innovations made, the equipment installation philosophy and results, and the equipment performance realized to date for the monobore completions in Qatar's offshore North Field.
Control of Microbiological Activity in Biopolymer-Based Drilling Muds
Authors: Ezzat A. M. , Rosser H. R. , Al-Humam A. A. 
Published: December 2007

Abstract
Water-based drilling mud formulations routinely include organic polymers as viscosifying and fluid loss control agents. These organic polymers, which are generally of either plant or microbiological origin (hence, "biopolymers"), can be degraded and utilized as nutrients for growth by naturally-occurring oilfield bacteria. This may occur despite the inclusion of biocide in some polymer preparations. Microbial growth in the mud can result in contamination of the well and near-wellbore zone. Fouling, corrosion and reservoir souring may then occur during subsequent operations. If growth in the mud is extensive, significant biopolymer degradation can be expected, with consequent loss of the mud's rheological properties. In these circumstances, additional polymer must be added to the contaminated drilling mud in an attempt to maintain viscosity and prevent excessive fluid loss. As additional biopolymer is added, and biodegradation continues, the cost of the drilling mud increases.
This paper addresses the requirement for control of microbiological activity in water-based drilling muds representative of those used in Saudi Arabia. A laboratory investigation of the relative efficacy of alkaline pH (lime) and biocide (glutaraldehyde) treatments in limiting microbiological activity in drilling muds is presented, and minimum treatment levels for absolute control of general aerobic bacteria (GAB) and sulfate-reducing bacteria (SRB) are provided. Application of these findings can be expected to minimize drilling mud biodegradation, and costly post-drilling operational problems such as production tubing and pipeline corrosion.
Minimization of Vertical Migration of DNAPLs Using Surfactant Enhanced Aquifer Remediation at Neutral Buoyancy
Authors: Shook G. Mike , Kostarelos K. , Pope G. A. 
Published: December 2007

Abstract
Remediation of water-bearing formations contaminated by organic liquids continues to be a challenge faced by both the public and private sectors.3 Chlorinated solvents such as trichloroethylene (TCE) are especially troublesome since they are denser than water and tend to migrate downward below the water table. Dense organic liquids such as this are commonly referred to as dense nonaqueous phase liquids (DNAPLs) and are particularly difficult to locate and remove from aquifers. 11 Surfactant Enhanced Aquifer Remediation (SEAR) has recently been shown to be an effective method for remediating chlorinated solvents from alluvial aquifers, but in aquifers without a proven aquiclude there are serious concerns about the risk of further downward migration of these solvents when the interfacial tension is reduced by the injected surfactant. To address this concern, we have developed a new version of SEAR called neutral buoyancy SEAR that minimizes this tendency and is especially targeted at those aquifers without a sufficient capillary barrier such as impermeable clay below the contaminated water-bearing formation.
Concentric Drilling Risers for Ultra Deepwater
Authors: Herrmann R.P. , Shaughnessy J.M. , Beynet P.A. 
Published: December 2007

Abstract
Use of a higher pressure rated riser run inside the marine drilling riser would provide floating rigs with some advantages enjoyed by fixed rigs; the potential to drill underbalanced or near balanced, improved gas handling capability, improved well testing capability, expanded kick control capabilities and increased mud weight rating. Drillers have found areas in ultra-deepwater where the fracture gradient is close to the pore pressure within a few thousand feet of the seafloor. These wells cannot be drilled with conventional equipment. Underbalanced or near balanced drilling which has been successfully used onshore may be the only method to drill such formations. The concentric riser would make it possible. The time and equipment required to test a deepwater well would be significantly reduced if a conventional surface type hook up could be used. However, few rigs will be able to run a concentric riser. The latest generation of drillships, such as the Discoverer Enterprise, will have the capability and equipment to do so. The paper will address the advantages, the operational procedures and hardware needed to utilize a concentric riser safely
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