bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Solids-Free Drill-in Fluid for Low Permeability Reservoirs
Authors: Cobianco S. , Bartosek M. , Lezzi A. , Massara E. Previde , Guarneri A. 
Published: December 2007

AbstractThe most widely used drill-in and completion fluids for seepage loss control in payzone are water-based mud containing polymeric additives and sized calcium carbonate or sized salt. These inorganic bridging solids are very effective in sealing the pore throats of the porous matrix and preventing formation damage but owing to their brittleness they will grind down during circulation and handling. This particle degradation makes it difficult to maintain the correct particle size distribution during drilling operations and can cause a deep penetration of the finest solids into the formation.A novel, solids-free drill-in fluid system containing a biopolymer as viscosifier and a highly crosslinked starch and microfibrous cellulose as fluid loss control agents has been developed for drilling and completing low permeability formations. This fluid composition provides the qualities of both good drilling mud and a non-damaging completion fluid. This paper presents the laboratory results obtained from coreflooding tests carried out on this solids-free drill-in fluid in limestone cores with permeability lower than 100 mD. The synergistic interaction of the biopolymer with a highly crosslinked starch and a microfibrous cellulose material promotes the quick formation of a very thin (ca. 50-60 µm) and impermeable filter cake which prevents polymer and drilled solids invasion into the core. The results show that the filter cake can be completely removed by backflooding and the permeability can be completely recovered. The non-damaging effect of this drill-in fluid was also observed when its density was increased to 1.48 g/cm3 by potassium formate brine. Good filtration and rheological properties were also maintained when simulated drilled solids, e.g. reactive and non-reactive clays were added. Core plug invasion and thickness and the morphological structure of the filter cake, investigated by means of Scanning Electron Microscopy, is also discussed.
Water-Dispersible Resin System for Wellbore Stabilization
Authors: Eoff Larry , Chatterji Jiten , Badalamenti Anthony , McMechan David 
Published: December 2007

Abstract
Global economic conditions require innovative and state-of-the-art wellbore-stabilization methods to reduce the total cost associated with the construction and life cycle of a well. Stabilization includes preventing unwanted fluid or gas flow into or out of the wellbore, preventing the flow of particulates into the wellbore, and mitigating formation compressive or tensile failure. Solutions should involve the use of real-time drilling data obtained from measurement-while-drilling (MWD) and logging-while-drilling (LWD) systems, advanced fluid chemistries, computer-generated placement procedures, and job histories of similar well problems. The end result of a properly designed wellbore stability process is reduced well-construction cost. Costs are reduced by minimizing nondrilling rig time, eliminating emergency or unplanned casing strings, and reducing unwanted fluid/ gas flow that causes environmental hazards.
This paper focuses on a water-dispersible, aliphatic epoxyresin system (WDR) that has been developed to plug fractures/ vugs, reduce formation permeability, and artificially increase formation fracture gradients. Aliphatic epoxy resins impart water compatibility, which is an advantage over more commonly used aromatic epoxy resins that cannot tolerate water contamination. The aliphatic epoxy-resin system can be used during drilling and can be pumped as a neat resin, resin/sand or resin/ barite mixture, or dispersed in water- or oil-based drilling fluids. A pill can be spotted over trouble zones followed by a pressure squeeze that forces resin through the mud filter cake, where it then hardens and consolidates the formation. This paper presents data that illustrate the system's capability to reduce permeability, dramatically enhance mechanical properties of the formation, and solve various production-related wellbore stability problems such as annular casing pressure, water production, and multilateral junction sealing.
Optimization of SBM Formulations for Minimum Damage
Authors: Herzhaft Benjamin , Audibert-Hayet Annie , Sandford Rick , Freche Patrick 
Published: December 2007

Abstract
Synthetic based mud formulations (SBM) are specially proposed to drill long open hole sections since such formulations present enhanced lubricating properties and limit torque and drag problems. When the mud is in contact with horizontal open hole section for a long period of time in overbalanced conditions, it induces invasion phenomena that may be detrimental for reservoir productivity.
Formation damage due to OBM or SBM is largely due to solid invasion occurring during the first steps of filtration when an internal filtercake is built. The damage is evaluated in terms of cake formation, filtration volume and back flow properties. During the back flow, when the cake is partially or totally removed, an overpressure to initiate flow through filter cake, named flow initiation pressure (FIP) appears and may affect the porous media stability. In case of unconsolidated reservoir, such a pressure may induce fine particle production which may affect the surface facilities and have to be removed from the production fluid.
Additives used in OBM formulations may either be dispersed or solubilized in the oil phase. A comparative study was performed with two kinds of additives through classical mud tests i.e. rheological characterisation, emulsion stability and static filtration tests and formation damage experiments on natural cores put under downhole saturation conditions. Organo soluble additives may enhance the cake properties and limit the invasion both under dynamic and static conditions. The dynamic filtration properties were studied on a large range of reservoir permeability. Compared to a classical additive, the organo soluble additive used in a SBM formulation induces a lower invasion on low permeabilities.
On high permeability sandstone, it was noticed that the invasion is not damaging since during the black flow, the pressure evolved as a function of time up to a constant low value. This indicates a high value of ultimate return permeability due to the production during the back flow of the additives present in the filtrate but removable in the oil flow.
Permeability Modifications by In-Situ Cations Hydrolysis
Authors: Busolo M. A. , Mogollón J. L. , Rojas Freddy 
Published: December 2007

Abstract
The precipitation of inorganic compounds by cation hydrolysis could be an alternative method to modify injection and production profiles. The precipitation in porous media can be caused by a pH increase as result of fluid-rock interactions, direct neutralization with base or thermal decomposition of a basic precursor, placed as additive. This paper ascertains the effects of precipitant solutions of zinc or aluminum salts, plus urea as basic precursor, on permeability, at reservoir conditions.
Flow tests were conducted in 30 cm Berea cores, at 140°C, 800 psi. Different injection schemes were tested, varying the number of precipitant solution batches, i.e. 1 and 2, and the shut-in time, i.e. 24 and 48 h. After that, fresh water was injected to determine permeability reduction, as well as the effect stability, along the core and in 3 sections of 10 cm each.
The results show 98% as maximum permeability reduction located mostly in the inlet section, while in the outlet section the maximal reduction achieved was 80%. In all cases, the effect was stable for at least 10 PV of water injected. Furthermore, permeability was not restored by 0.1 N HCl solutions. Precipitation occurs at T&gt;70 ºC; it takes 2-4 hours at 80 ºC, and 40 min. at 140 ºC; enough time for the placement of the solution into porous media. Scanning electron microscopy images of the treated Berea cores demonstrated different shapes of particles precipitated, depending on the cation; all of them reduce permeability by filling the porous space.
The aforementioned results show that in-situ cations hydrolysis induced by basic precursor have the potential to modify injection and production profiles in the field, with some possible placement advantages.
Paraffin Deposition in Oil Production
Authors: García María del Carmen 
Published: December 2007

Abstract
Paraffin deposition problems in oil production, transportation and storage will be presented. An experimental methodology for deposits characterization and paraffin deposition control, oriented toward the identification of "tailor made" preventive or remedial treatments, will be shown. Research results including some correlations between oil composition and wax appearance temperature (WAT), as well as paraffin inhibitors efficiency, will be presented. The knowledge provided in this paper has direct application to paraffinic crude oils productivity enhancement in terms of costs reduction (cleaning and deposits removal), and oil production improvement. On the other hand, correct selection of a prevention treatment will avoid extremely expensive and inefficient "trial-and-error" procedures, and even severe formation damages due to eventually paraffin deposition in the reservoir. This last phenomenon can be a consequence of the precipitation of crude oil paraffin's heaviest components after improper operations, like "hot-oil" treatments. The designed experimental strategy starts with the deposit analysis, which includes a preliminary physical separation of the organic and inorganic components. The organic fraction characterization, in terms of its hydrocarbon components, allows to discriminate between wax and asphaltenes plugging. Once the paraffin deposition problem is identified, the original crude oil characterization is carried out. Specific compositional characteristics of the crude oil allow to select an adequate paraffin deposition treatment, based on previously established correlations. An example selected from field operations carried out in Venezuelan facilities, will illustrate the benefits derived from this methodology.
Successful Applications of Anti-agglomerant Hydrate Inhibitors
Authors: Frostman L. M. , Przybylinski J. L. 
Published: December 2007

Abstract
While it is important to approach each system individually when dealing with new types of performance chemicals, the anti-agglomerants have been found to be suitable for hydrate control in most of the situations encountered in offshore oil production. Anti-agglomerants have now been used in several field applications in deepwater systems - both in subsea wells and dry tree wells - under both flowing and shut-in conditions. During these applications, no hydrate problems were observed. The anti-agglomerants caused no upsets in the topsides operations; there were no emulsion problems, no foaming problems, and no water quality problems. The products were deployed through the existing methanol injection systems without incident. Application rates were significantly lower than if methanol were used. Potential advantages of the anti-agglomerants over methanol include smaller umbilicals, smaller pumps, smaller storage facilities, and less frequent supply trips.
Money Left On The Table In Sealed, Competitive Bidding: Federal Offshore Oil And Gas Lease Bids
Authors: Dougherty Elmer L. , Lohrenz John 
Published: December 2007

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

Abstract
The expected values of money left on the table are evaluated for lognormally distributed, sealed, competitive bids. Functions are developed and evaluated that can be used to make a priori predictions of money left on the table and a posteriori comparisons with actual bids. Extensive comparisons of federal offshore oil and gas lease bids show agreement with the theoretical function except that some extreme bids appear to depart from lognormality.

Introduction
We do not know the competitive bidder who first bewailed the amount of "money left on the table" after winning by being the highest (or lowest) with a sealed, competitive bid. The phrase may be colloquial, but the meaning is phrase may be colloquial, but the meaning is clear. If the highest bid wins, money left on the table is the amount by which the winning, highest bid exceeds the next highest bid. Money left on the table is the amount of money bid in excess of what would have been necessary to win had the bids been known.
Since the first federal offshore oil and gas lease sale on Oct. 13, 1954, through a sale held on July 29, 1975, 2,580 leases receiving 9,142 sealed, competitive bids were issued to the highest bidders. The winning bidders spent over $15 billion for the leases, leaving about one-half of that money on the table. Thus, studies in the statistics of money left on the table have a practical cogency.
We used these 2,580 leases as a data base throughout this study. All 9,142 sealed, competitive bids were used excepting 170 (1.9 percent of the total), which were deleted as percent of the total), which were deleted as low, noise bids using the 30–30 deletion algorithm* of Dougherty and Lohrenz.

A BRIEF REVIEW AND SOME DEFINITIONS
Previous studies have provided the practical and statistical basis for considering practical and statistical basis for considering federal offshore oil and gas lease, sealed, competitive bids as lognormally distributed. Dougherty and Lohrenz used -the lognormal distribution and derived an expression giving expected values of money left on the table as a function of the standard deviation of bids, and the number of bids per lease, n.
Rheological and Structural Properties of Heavy Crude Oils in Relation with their Asphaltenes Content
Authors: Hénaut I. , Barré L. , Argillier J-F. , Brucy F. , Bouchard R. 
Published: December 2007

Abstract
Heavy oils represent a strategic source of hydrocarbons as their reserves are of the same order of magnitude as the ones of conventional oils. The production of these crudes remains low, in particular because of their very high viscosities. The asphaltenes which they contain are known to be responsible for this situation. Actually, many studies have shown that these high molecular weight polar components self-associate more or less severely depending on different parameters like temperature, concentration and solvent quality. The experimental work was usually performed using simple organic solvents (toluene, heptane…) which are not representative of complex heavy crude oils. Therefore, we decided to investigate the rheological behavior of asphaltenes in their natural environment and in relation with their structure. Samples coming from the same crude oil were prepared with different asphaltenes contents, from 0 to 20% in weight. The apparent viscosity and the oscillatory modulus (G' and G") were measured with a controlled stress rheometer and SAXS were undertaken. Two domains were identified. The first one concerns the dilute samples for which the relative viscosity increases linearly with the weight fraction of asphaltenes. In this domain, the aggregates of asphaltenes stay independent from one another and have the same radius of gyration. For the more concentrated samples, the viscosity increases dramatically because of the aggregates entanglement as was observed by SAXS. Concerning the oscillatory experiments, the elastic character increases from the first domain to the second one, which confirms that a structural change occurs. Combining the rheological measurements and SAXS reveals an analogy between heavy crude oils and concentrated colloidal systems of polymer solutions. All these results help the understanding of the flow properties of heavy crude oils and aim to contribute to the improvement of their transport.
A Field Case History: Chemical Treatment of a Produced-Water Injection System Using Anthraquinone Improves Water Quality and Reduces Costs
Authors: Law M. D. , Kretsinger M. B. , Burger E. D. , Schoenenberger J. G. , Ulman M. A. 
Published: December 2007

Abstract
Sulfate-reducing bacteria (SRB) are notorious for causing decreases in the quality of oilfield injection waters due to their ability to increase total suspended solids (TSS). Through dissimilatory respiration, SRB reduce sulfate to sulfide, which subsequently forms hazardous hydrogen sulfide (H2S) gas. H2S is not only an environmental health threat, but it also can indirectly contribute to decreased water injectivity by reacting with soluble iron to form iron sulfides. These very tenacious solids can plug formation faces, thereby reducing the volume of water a well can take at a specified injection pressure. A previously reported study showed that an anthraquinone treatment program was capable of controlling biogenic H2S generation while maintaining TSS within field specifications (SPE 50741). Subsequently, an anthraquinone program was initiated in Chevron's Lost Hills Field (California) produced water injection system. Chevron's water treatment program had been a continuous injection of a quaternary biocide compound plus a weekly slug dose injection of another biocide (acrolein) to control SRB, TSS and H2S. Chevron also maintained a monthly pigging program that required the disposal of classified hazardous wastes due to the continuous injection of the quaternary chemical. The new treatment program included weekly slug injections of acrolein followed by a slug dose of a soluble form of anthraquinone. The monthly pigging program was maintained, but the continuous quaternary compound usage was eliminated. This paper describes the produced water injection system, the treatment program and the parameters monitored, including TSS, SRB, and H2S levels before and after the implementation of the anthraquinone treatment program. These data show that the new program has resulted in injection water quality which is currently better than previously measured during the recent history of the field and which now for the first time consistently meets Chevron's TSS specification.
Mineral Scale Control in a CO2 Flooded Oilfield
Authors: Yuan M. , Mosley J. , Hyer N. 
Published: December 2007

Abstract
This paper presents a case study of improving scale inhibition treatments in the Sharon Ridge Canyon Unit (SRCU), West Texas in response to the increased scaling conditions that has arisen from carbon dioxide (CO2) injection into the oil reservoir.
In anticipation of increased scale deposition, a proactive approach was taken by carrying out a comprehensive field system analysis and scale survey prior to the commencement of CO2 flooding at SRCU. This analysis/survey was intended to assess the new situation and come up with a cost effective scale treatment program. A laboratory evaluation of a number of scale inhibitors was then carried out. Based on our understanding of the problem and the lab evaluation results, a new scale inhibitor and a new chemical treatment program were developed and implemented in the field.
This paper describes the system analysis/scale survey and highlights its importance in understanding the changing situation and the new challenges in scale inhibition arising from CO2 flood. The laboratory evaluation for identifying the most suitable and cost-effective inhibitor is then briefly described. The paper then discusses the new scale inhibition treatment program and scale monitoring program. The field results from implementing the new treatment program are presented and discussed. Owing to the proactive approach and the improved inhibitor and treatment, the field production system and water re-injection system have not been troubled with scale deposition.
A Novel Self-Diverting-Acid Developed for Matrix Stimulation of Carbonate Reservoirs
Authors: Chang Frank , Qu Qi , Frenier Wayne 
Published: December 2007

Abstract
A Self-Diverting-Acid (SDA) using a Visco-Elastic Surfactant (VES) has been developed. The viscosity of the solution does not develop until the acid reacts with carbonate in the formation. The increases in Ca2+ ions and pH due to the HCl-carbonate reaction cause in situ gelling of the acid. The high viscosity temporarily blocks the wormholes formed in the rock matrix, allowing the acid to cover the un-acidized area. The viscosity of the gelled acid can be completely reduced by post flush of solvent or by the hydrocarbon in the formation during flow back. Unlike the polymer based gelled acid systems, the new material does not leave any residue once it has broken. Multi-Core flood testing incorporating a post acidizing Computed Tomography (CT) scans showed that the VES based Self-Diverting-Acid successfully diverted acid from high permeability section into lower permeability sections. The rock face remained clean without any trace of residue. Rheology measurements showed the consistency of the viscosity development by the gelled acid upon reacting with carbonates.
Crosslinked Emulsion To Be Used as Fracturing Fluids
Authors: Kakadjian S. , Rauseo O. , Márquez R. , Gabay R. , Tirado Y. , Blanco J. 
Published: December 2007

Abstract
A new crosslinked oil-in-water emulsion system has been developed for hydraulic fracturing treatments. The external phase contains polysaccharide which acts as thickening agent. Different polymers have been evaluated in order to obtain a stable emulsion. The oil phase contains a refined petroleum fraction such as gas oil or paraffin oil. A mixture of surfactants has been used to provide a stable emulsion in the preferred volume ratios of the oil and water phases.
The emulsions have been crosslinked using borate salts and pH controllers to obtain viscosity up to 400 cP @ 170 s−1/170 °F which allows proppant transport up to 15 lb/gal. Polymer loading in the emulsion system has been lowered to 18 lb/1000 gal which would give excellent regained conductivity in comparison to high polymer loading commercial systems at the same conditions.
The system has been broken using conventional oxidizer breakers, lowering the viscosity below 40 cP @ 170 s−1/140 °F after 2.5 hours of rheological evaluation. Qualitative tests in sealed bottles have shown that one of the advantages of the crosslinked emulsion is that once the system is broken, the solids are dispersed into the emulsion. This phenomenon is crucial for reducing formation damage caused by the stimulation treatment and maintaining the original proppant conductivity.
This fluid would fulfill the requirements of fracturing fluids of having good fluid loss control during fracturing and being capable of suspending and transporting proppant for better fracture packing.