bluuebunny/crossref_metadata_2025_split huggingface dataset:
Novel Application of Sodium Silicate Fluids Achieves Significant Improvement of the Drilling Efficiency and Reduce the Overall Well Costs by Resolving Borehole Stability Problems in East Africa Shale
Authors: El Essawy Wael M. , bin Hamzah Rosli , Malik Mirghani Mohamed , Knox David , Monem Mohammed R. , Oswald Reinhard J. 
Published: December 2007

Abstract
Historically, wells drilled in East Africa and mainly in Sudan have experienced drilling related problems due to the highly reactive and dispersive shales of the Aradeiba formation. Hole instability problems have included washed out hole sections combined with tight hole and poor coring efficiency. Frequent wiper trips were required and logging of the wells was not always successful.
Over time, several conventional inhibitive water-based drilling fluid types have been used, such as KCl/polymer, KCl/lime/polymer, KCl/PHPA, and KCl/glycol, but with only marginal improvements in hole stability and drilling performance. A sodium silicate/KCl system was designed to provide the necessary inhibitive qualities. The first field trial well in East Africa was drilled with a sodium silicate/KCl system and the following benefits were observed:24% reduction in drilling daysShale drill cuttings with exhibited excellent integrityNo evidence of cuttings hydration or dispersionReduced wiper tripsCaliper logs indicated in-gauge wellboreLogging program completed as per programExcellent coring efficiencyLow filtrate invasion
This paper describes the extensive technical teamwork between the service company and the operator that led to the development and successful application of a sodium silicate drilling fluid for use in the Aradeiba stressed shale sections.
The paper includes a description of the formulated silicate fluid and test data from the extensive laboratory testing. Enhancements in drilling and coring performance over other inhibitive water-based drilling fluid systems are documented and reviewed, in particular coring efficiency (hole stability in the shale zones, elimination of core jamming) and improved core data acquisition (obtaining fresh-state core samples with minimal mud filtrate invasion).
As a result of this fluid design and application, an additional thirty wells have been drilled with the sodium silicate system in the area, including the highest temperature well ever drilled in the world with a silicate drilling fluid.
Casing Strength Degradation due to Corrosion - Applications to Casing Pressure Assessment
Authors: Sun Kai , Guo Boyun , Ghalambor Ali 
Published: December 2007

Abstract
Well casings are subjected to severe corrosion because of their exposure to corrosion environments – seawater, saline formation water, and the corrosive fluids that are transported. Corrosion develops pits and cavities at both the inner and outer walls of the casing. The burst and collapse loads are the most common loads for casing under operation conditions. The loads act on the pitted casing will cause stress concentration and degraded casing strength. The strength deterioration can significantly shorten the casing life; even cause failure of the well. Thus, it is highly desirable to know the stress concentration factor (SCF) for both casing designing and evaluation processes.
The degree of stress concentration depends on the cavity shape. This paper derives simple formulae for SCF around cavities of various geometries including shallow-spherical (depth is less than the open radius), exact hemispherical (depth is equal to the open radius), and deep-spherical (depth is greater than the open radius) cavities. SCF graphs are generated and results of sensitivity analyses are presented. A comparison analysis of the shallow-spherical, exact hemispherical and deep-spherical cavities SCF formulae is also presented. The analysis shows that the shallow-spherical and deep-spherical formulae give almost the same SCF results. Thus, any shallow-spherical or deep-spherical formulae can be used in designing and evaluating casing with spherical cavities. Finally, application procedure for predicting the degraded casing strength is illustrated in this paper.
Fracture Pressure Gradient in Deepwater
Authors: Rocha Luiz A. S. , Falcão José L. , Gonçalves C. J. C. , Toledo Cecilia , Lobato Karen , Leal Silvia , Lobato Helena 
Published: December 2007

Abstract
The majority of the petroleum engineers agree that fracture pressure gradient is one of the most important items to be considered when designing or drilling a well.
The perception of the importance of the fracture pressure gradient comes from the results of the severe economic losses that the oil industry has faced when dealing with lost circulation related problems. In the worst scenario, these problems can escalate to a blowout due to the reduction of the hydrostatic pressure in the well. In addition, lost circulation problems are likely to occur and become even harder to control if the well is in deepwater.
It is well known that a correct prediction of the fracture pressure gradient minimize drilling problems. However, the methods used by oil industry to perform this task are generally based on equations or methodologies that give questionable results and do not match actual field data.
Fracture pressure gradient methods are generally based either on equation derived from rock mechanics theories or in simplified methods. Although, the first tries to closely represent the rocks underground behavior, they are too complex and call for a number of data that normally are not available. On the other side, the second carries many simplifications and barely represents subsurface conditions. However, the last is simple to use and consequently more popular among drilling personnel. Regardless of the method, a good calibration, in general hard to be accomplished, is always necessary to provide good estimates.
Finally, performing leak off tests (LOT) is usually the procedure carried out by most of the oil companies to establish fracture pressure gradient values for a given area. Once LOT`s are obtained, they are used to calibrate simple equations or will be part of the company database to simply build fracture pressure gradient curves.
The objective of this work is to make a critical examination of the current methods used to estimate fracture pressure gradient. The work also presents simple methodologies based on leak of tests data to estimate fracture pressure gradient for a given area. Results based on actual field data to exemplify the use of the presented methodology will be shown, mostly for deepwater oilfield.
The Cement-to-Formation Interface in Zonal Isolation
Authors: Ladva H. K. J. , Craster B. , Jones T. G. J. , Goldsmith G. , Scott D. 
Published: December 2007

Abstract
Maintaining zonal isolation for the lifetime of oil and gas wells is critical. Leakage behind casing can reduce the cost-effectiveness of the well and cause health and safety risks from pressure build-up and contaminated aquifers. During the completion and production phases of the well, temperature and pressure variations can cause stresses at the cement-to-formation interface. The ability of the casing-cement system to maintain a seal at the cement-to-formation interface depends on the condition of the formation surface prior to slurry placement. The condition of a shale will depend upon the nature of the drilling fluid used, whereas the condition of a permeable rock will depend upon the presence and nature of the filtercake deposited during drilling and circulation.
In this paper we present an improved understanding of chemical interactions at the cement-to-formation interface and the factors that determine bond strength and the position of the plane of failure. For permeable formations, the role of the mud filtercake for different mud types is explored. For nonpermeable formations, the presence and effect of a residual mud film are also examined. The extent and depth to which chemical alteration of the mudcake occurs when in contact with cement are determined, together with measurements of the yield stress and water content profile of the altered mudcake. The effect of exposing swelling and nonswelling shales to inhibitive drilling fluids on bond strength is presented. Laboratory-scale test equipment and a small-scale wellbore simulator, developed for tests under realistic field conditions, are described. The flexibility of cement plays a role in bonding and is demonstrated by the simulator tests. This improved understanding allows us to confirm the key issues at the cement-to-formation interface and propose some solutions for effective zonal isolation.
Lightweight Cement Slurries Using Multifunctional Liquid Additives: A New Approach to Offshore Well Construction
Authors: Kamolchai Pattanapong , Keittipong Kaotun , Jeff Hibbeler , Phil Rae 
Published: December 2007

Abstract

Proposal
Recent technical and logistical challenges in the Gulf of Thailand have driven the development of a new approach to lightweight cementing. The industry has evolved from numerous and complicated dry cement blends being used on 45-day well constructions to the present minimum liquid additive, lightweight, single slurry approach used on 5-day wells. As nearly all wells are now slimhole monobores, the cement job has become one of the most important operations in the life of the well. The absence of packers or other isolation devices means that the cement job functions as a primary pressure barrier and is the only technique to isolate the numerous sands in each well. This combined with the logistic issues of fast offshore batch drilling exact a premium on cementing products and the entire cementing process itself.
For offshore applications it is advantageous to use an all-liquid system so as to avoid relying on mud pits to blend mixwater, to avoid the confusion of multiple dry blends in the field and to have flexibility to make last minute changes in slurry design. Recently a new approach to lightweight cementing using Multifunctional Liquid Additives (MLA’s) was developed so that on-the-fly mixing is possible with only three to four streaming additives. MLA’s have reduced what used to be a complicated set of dry blends to a few liquid additives. By simply adjusting the cement:water ratio and MLA concentration, the same base slurries can be tailored for nearly any scenario. This approach has been used recently in PTTEP’s Arthit gas field to construct a 1.60 SG. production string slurry at 190°C. The same additives work for shallow gas where temperatures are over 150°C cooler. Because the systems are so robust, slurry charts have been implemented such that the rig can decide what slurry to pump based on a given bottom hole circulating temperature (BHCT) and desired thickening time.
This paper illustrates the various ways lightweight slurries using MLA technology have created a new approach to offshore well construction in The Gulf of Thailand.
Maximizing Production with 13Cr Solid Expandable Tubulars in Sarawak Gas Fields
Authors: Bada Inyau , Maekiaho Leo , Ain Fitzerald Mathew , Nijveld Erik , Tan Ivan , Book Larry , Dubedout Laurent 
Published: December 2007

Abstract
Solid expandable tubular technology presents an opportunity to significantly boost the production capacity of wells by increasing the size of the completion. As such, it offers an economically attractive and environmentally friendly option to breathe new life into gas fields. It is flexible in its application, and can be applied fast to react quickly to changes in future gas demand. It makes effective use of existing surface facilities, and does not affect abandonment costs.
This paper describes the planning and installation of the world's first 7-5/8" 13Cr (13% Chromium) solid expandable tubular workovers in the F23 gas field in Sarawak. A significant amount of development work, modelling and testing was done to deliver components required for the installation. The solid expandable tubular workover resulted in an increase of 50% in well capacity for one of the wells of which the production results were known at the time of writing this paper.
Experimental Determination of the Variation of Torsional Resistance of Mudcakes with the Variation of Mud and Mudcake Composition
Authors: Amanullah Md. 
Published: December 2007

Abstract
Torque and drag problems are major operational problems in deviated, horizontal and extended reach wells. Hence, management of torque and drag resistance of mudcakes as low as possible is an important design consideration for a superior mud design for horizontal and extended reach wells.
Several mudcakes of variable compositions were tested using a newly developed test facility. The results indicate that the torsional resistance of mudcakes is strongly influenced by the physics and chemistry of the mud additives. Fresh water-based bentonite mudcake gave the lowest torsional resistance and starch containing salt water based NaCl-bentonite mudcake gave the highest torsional resistance. The presence of salts, especially salts containing divalent and larger hydrated ionic diameter cations dramatically increases the torsional resistance of bentonite mudcake. The drilling engineering implication of this observation is that salt contamination of bentonite mud may turn the mudcake more shear resistant and thus expected to create higher torque and drag problems. The presence of barite in a fresh water based bentonite mud also increases the shear resistance of the mudcake. Hence, mudcake deposited by a weighted bentonite mud is expected to cause increased torque and drag problems. The contamination of bentonite mud by cations of smaller hydrated ionic diameter (KCl salt) causes a smaller increase in torsional resistance compared to the presence of cations of larger hydrated ionic diameter (NaCl and CaCl2 salts). The presence of anionic CMC (carboxy-methyl cellulose) in NaCl-based salt water mud caused negligible changes in the torsional resistance of the mudcake. However, the presence of polyanionic cellulose (PAC) in the mud caused a significant reduction in the torsional resistance of salt water-based mudcake. The drilling engineering significant of this observation is that the fluid loss additives like PAC is more suitable for deviated, horizontal and extended reach drilling to minimise the torque and drag problems.
A Technical Evaluation of a CO2 Flood for EOR Benefits in the Cooper Basin, South Australia
Authors: Bon J. , Sarma H. K. 
Published: December 2007

Abstract
This study evaluates reservoir and reservoir fluid parameters relevant to CO2 flooding to enhance hydrocarbon recovery from a Cooper Basin oilfield (Field A), located in South Australia.
Field A is a tight (k&lt;1mD) sandstone reservoir containing volatile and low viscosity oil. CO2 could be separated from raw gas produced from a nearby gas field (Field B) or made available from a gas processing facility located some 60km from Field A. The costs of preconditioning the CO2 to suitable composition and pressures are known to be high, but have not been considered in this study.
Laboratory experiments were conducted using both pure carbon dioxide and a synthesized gas derived from Field B gas, consisting mainly of CO2 and methane. The increase in oil recovery as a function of pressure was determined, which would be a basis for selection of injection pressure. In addition, minimum miscibility pressures using both CO2 and the synthetic gas mixture and the utilization factor of CO2 injected to oil produced were also determined.
High Concentration Polymer Flooding is Successful
Authors: Yang Fulin , Wang Demin , Yang Xizhi , Sui Xinguang , Chen Qinghai , Zhang Lei 
Published: December 2007

Abstract
Recently, new evidences show that the recovery factors of both partially hydrolyzed polyacrylamide (HPAM) and xanthan gum (XA) flooding increase with higher concentration and higher viscosity. However, when the incremental oil recovery of XA flooding in artificial cores reaches about 8.6% OOIP (original oil in place), the displacement efficiency of XA flooding levels of, but an incremental oil recovery of more than 20% OOIP can be obtained from HPAM flooding with a high concentration, the higher the concentration the higher the recovery, the recovery does not level of. The difference in recovery between the two solutions is due to the visco-elastic properties of HPAM. The visco-elastic property of HPAM fluid not only increases the volumetric sweep efficiency but also the displacement efficiency of the pay zone on a micro scale. A novel method has been developed to enhance the oil recovery in highly heterogeneous and high permeable reservoirs. The results on artificial cores with a Dykstra-Parson Coefficient of 0.72 show that an incremental recovery over water flooding of more than 20% OOIP can be obtained by early time injection of the high molecular weight, high concentration polymer solution, the earlier the better. The incremental recovery is comparable to surfactant flooding but at a lower cost.
In Daqing Oil Field, a pilot test of high concentration polymer injectivity was conducted on 6 injection wells in August 2002. Three wells are injecting in high permeable pay zones and the other 3 wells in low permeable pay zones. The range of effective permeability (Keff) of the pay zones is 0.354 ~1.06 um2. The results show that high permeable formations (Keff&gt;0.890um2) are suitable for continuous injection of high concentration polymer solutions (concentration 2,000 ppm ~2,500 ppm, molecular weight 17 million Daltons, viscosity 200~250 mPa.S). There were 22 oil wells around the 6 dispersive polymer injection wells. In February 2004, the average fluid production of each well was 90.2 tons per day, the average daily oil production of each well was 21.7 tons and average water cut was 79.5%. Compared to low concentration (1,000 ppm) solution flooding, the fluid production per day of each well remained and the daily oil production of each well increased by 3.4 tons (an increase of 18.6%) and the average water cut decreased by 1.0%.The average water cut decreased by a maximum of 7%.The results show that the injection of high concentration polymer fluid is very effective and the pilot area will be further expanded.
Field Implementation of Alkaline-Surfactant-Polymer (ASP) Flooding : A maiden effort in India
Authors: Pratap Mahendra , Gauma M. S. 
Published: December 2007

Abstract
The Viraj oil field lies in Ahmedabad-Mehsana tectonic block of Cambay Basin in India. The field has been under exploitation for the last nearly two decades and produces 18.9°API oil from the sandstone reservoir with an average porosity of 30%and permeability ranging from 4.5 to 9.9 Darcy. Reservoir temperature is 81°C and initial reservoir pressure is 135 kg/cm2. Ultimate oil recovery estimated from the field, producing under active water drive, is 32 % of OIIP.
After analyzing the rock and fluid properties, extensive laboratory studies were undertaken on native cores by R & D institute of ONGC to evaluate the efficacy of Alkaline – Surfactant – Polymer (ASP) process in Viraj field. Laboratory studies indicated an incremental oil recovery of 18 % of OIIP over water flood. On the basis of these encouraging results, a pilot was designed with four inverted 5-spot patterns. Facilities have been created to ensure proper dosing of chemicals, optimum fluid injection and monitoring of injection fluid quality. A comprehensive data-acquisition strategy has been adopted right from the beginning. First phase of the pilot i.e. injection of Pre-flush and ASP slug(20 % PV) having composition of 1.5 wt.% alkali, 0.2 wt % (100% Active) surfactant and 800 ppm anionic polymer have been completed.
This paper aims to present salient features of the laboratory findings and the ASP pilot in progress. The data generated during the first phase of the pilot analyzed and presented in this paper shows encouraging results. Final evaluation of the pilot is, however, planned after completion of the targeted ASP/Polymer/Chase water injection.
Elasticity of HPAM Solutions Increases Displacement Efficiency under Mixed Wettability Conditions
Authors: Xia Huifen , Wang Demin , Wu Junzheng , Kong Fanshun 
Published: December 2007

Abstract
In this paper, the rheological characteristic of HPAM solutions is studied and the oil displacement efficiencies of viscous-elastic HPAM solutions (concentration in series) and viscous glycerin solutions (no elasticity, viscosity in series) are studied by flooding at visual microscopic glass models and artificial cores. Also, the effect and mechanism of the viscous-elastic behavior of HPAM solutions and glycerin solution on the displacement of residual oil films under mixed wettability conditions is studied, the relationship between the elastic behavior of HPAM and oil displacement efficiencies is given. The results of rheological characteristic measurement indicate that both the viscosity and the first normal stress differential (&lt;i&gt;N&lt;/i&gt;1) of HPAM solutions increase with the increase in concentration, HPAM solutions show strong viscous-elastic characteristics under high concentration conditions. The results of microscopic oil displacement experiments indicate the displacement efficiencies of HPAM solution flooding and glycerin solution flooding gradually increase with the increase in the viscous-elastic behavior of HPAM solutions and the viscosity of glycerin solutions. However, for HPAM solution flooding, the displacement efficiency is always higher and residual oil saturation lower than that of glycerin at the same viscosity and same capillary number. Last, the displacement experiment in artifical cores is conducted and the similar resultes are validated.
Prediction of Residual Water Saturation Using Genetically Focused Neural Nets
Authors: Ibrahim Mohd Azizi , Potter David K. 
Published: December 2007

Abstract
The "genetic petrophysics" approach for predicting petrophysical parameters using genetically focused neural nets (GFNN) has only recently been introduced. The approach only requires a minimum number of core plugs, along with associated wireline log data, from a chosen representative genetic unit (RGU). This case study has successfully developed and tested this new methodology to predict residual water saturation.
Combinations of wireline logs and core data from a short 7m RGU interval in a North sea well were used to train the GFNN predictors. These were then applied to predict the residual &lt;i&gt;SW&lt;/i&gt; throughout the whole logged section in the training well and adjacent wells in the same field. Traditional hydraulic unit analysis provided the basis for selecting the minimal training plugs. Only 4 core plugs were finally required to represent the hydraulic units in the RGU and provide good results. This approach is very cost effective in terms of core material and computing time.
Presently we have only tested this approach in oil bearing shoreface reservoirs. Thus, it is recommended that this approach be tested in other environments.
Comparative Simulation Study of Water Flood
Authors: Li Dacun 
Published: December 2007

Proposal
Secondary oil recovery led by water flood accounts for one half of the oil recovered in the United States. In addition, streamline simulation is becoming more and more popular these days due to its higher speed compared with finite-difference method. In this paper, a streamline simulator is developed for water flood based on analytical and numerical methods. Oil recovery and water cut from the streamline simulator are compared with their counterparts from a finite-difference simulator. In addition, a practical method to implement an extremely large time step in streamline simulation is introduced. Results show that numerical dispersions decrease from finite difference method, to numerical streamline method, and to analytical streamline method. For numerical method, numerical dispersions decrease with increased time step size. By using the new practical method, the streamline simulation can be greatly sped up. The streamline simulator can be run by using an extremely large time step, in which 0.13 pore volume of water is injected. About 10 time steps are needed for simulating the 1.2 pore volume injection of water.