bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Novel Approach to Predict the Co-Precipitation of BaSO4 and SrSO4
Authors: Li Ying-Hsiao , Crane Steven D. , Coleman James R. 
Published: December 2007

ABSTRACT
Co-precipitation of strontium sulfate with barium sulfate is often observed in oil fields. Some explanations have been given, but the mechanism is not fully understood. A numerical simulation approach gives a detailed explanation of its occurrence. This results in an improved tool for operators in dealing with prevention and treatment procedures.
The computer model simulates reactive flow through porous media since injection of an incompatible fluid can induce numerous chemical reactions in a reservoir. The model uses the Gibbs free energy minimization technique to calculate chemical reactions that include precipitation from dissolved ionic species and dissolution of formation rocks. The model applies finite difference technique to solve mass transfer of the dissolved ionic species by convective fluid flow and diffusion.
A case study of a North Sea seawater flood revealed the mechanism of strontium sulfate formation and its relationship to barium sulfate precipitation. Once seawater contacted barium (in the carbonate form) in the reservoir, barium sulfate dropped out immediately. This reaction also created excess carbonate ion (CO3−−). Furthermore, although strontium carbonate is more stable than strontium sulfate, redistribution of the available CO3− forced strontium carbonate to dissolve and strontium sulfate to form. The results also suggest that the formation of the sulfate scales is not only controlled by their equilibrium constants but also dependent upon the concentrations of all other ionic species in the immediate vicinity.
The simulation technique leads to a better prediction of the quantity and composition of sulfate scale formation. It also provides in-depth understanding of the interactions of the reservoir rocks with injected fluids. The application can also be extended to quantify the formation of other types of scales which occur during production operations.
The SPE Video-Tape Series for Continuing Education
Authors: Caudle B.H. 
Published: December 2007

Abstract
In early 1967, the SPE elected to make a video-tape course that could be used by the membership in small groups at remote locations. The first video-tape series was designed to be given in 13 weekly sessions, each session consisting of 3 hours. Approximately 2 1/2 hours of video-tape lecture was prepared for each session. A technique was developed whereby a lecture was accomplished with the use of a black brush pen on white paper. This first course covered basic mathematics, fluid flow, material balance, and well testing procedures which are applicable to reservoir engineering. A text was prepared to accompany the lecture. Homework was assigned to be done between the sessions, and a solution of assigned homework was put on the first part of the succeeding week's video-tape. Approximately 8 months after the completion of the first course, a follow-up course was produced using the same techniques as in the first course. The second course was designed for 12 weeks of study.
The two SPE video-tape courses are administered by the Society's headquarters office in Dallas. The courses are offered twice each year to sections, and playback equipment and tapes are then loaned to each group wishing to conduct a course. The costs of administration are partially deferred through enrollment fee partially deferred through enrollment fee to local members.
The Society has constructed a small television studio in its headquarters office and additional courses are being developed in order to expand the SPE Continuing Education Program.
Introduction
During the latter part of the 1960s, a large fraction of the society membership became interested in "refresher" and "updating" continuing education courses. Those members in large local sections were able to organize such courses while members residing near a suitable Petroleum Engineering school could attend classes there. However, a large part of the membership could not be satisfied thusly. In 1967, the Continuing Education Committee of S.P.E. (which had been active in helping larger sections to arrange their courses) turned their attention toward the development of continuing education for the more isolated members.
After some discussion, 1/2 inch video-tape equipment was selected to be the vehicle for these courses.
Beta Field History: Submersible Pumps in Heavy Crude
Authors: Carpenter D. E. , McCrea A. A. 
Published: December 2007

Abstract
Beta Field, offshore Long Beach, was developed in 1981 with electric submersible pumps as it's primary artificial lift. The produced oil gravity ranges from 10-19 API. The wells had low initial water cuts, which increased as the waterflood matured. The impact of viscous production and increased water cuts on the ESP run times are presented here. Despite these challenges, equipment life is currently at 594 days. Equipment sizing techniques and the failure history are also shared.
A Commercial Microbial Enhanced Oil Recovery Technology: Evaluation of 322 Projects
Authors: Portwood J. T. 
Published: December 2007

Abstract
This paper discusses a data-base of information collected from 322 projects, all treated with the same Microbial Enhanced Oil Recovery process. An analysis of the data quantifies the effectiveness and economics of this particular process, and is a source of information useful for predicting treatment response in any given reservoir.
A New Environmentally Safe Crosslinked Polymer for Fluid-Loss Control
Authors: Cole R. Clay , Ali Syed A. , Foley Keith A. 
Published: December 2007

Abstract
The adverse effects of inadequate fluid-loss control associated with gravel-packed completions is well known. Controlling fluid losses to the formation before and after pack placement is critical to ultimately achieving optimum productivity from a given well for the following two reasons:
Fluid-loss control is necessary to prevent losses of expensive high-density brines, sometimes used for well control in high-permeability, unconsolidated formations. The costly loss of expensive brines can also lead to critically unsafe well conditions, where high overbalance pressures are required to control highly geopressured zones. Dense brines have been reported as being difficult to unload from formations once losses have occurred.1 Calcium and zinc-bromide brines can form highly stable, acid-insoluble compounds when reacted with some formation brines. Because of the high density of these brines, stratification tends to further inhibit their removal. The most effective means of preventing the formation damage described is to limit completion brine losses to the formation.
Measuring Skin While Drilling
Authors: Engler Thomas W. , Osisanya Samuel , Tiab Djebbar 
Published: December 2007

Abstract
A new model is proposed to characterize the variation in skin effect along a horizontal well. Typically, a cylindrical-shaped damaged region is assumed; however, this work describes the damaged region as a combination cylindrical-conical shape. The shape of the damaged region and the severity of the damage is governed by the contact time of the drilling fluid with the formation. This time is a function of the drilling rate penetration (ROP) and the mud filtrate invasion rate. Simple, empirical models are used to provide ROP and mud filtrate invasion rate.
The effects of anisotropy ratio, penetration rates, and horizontal length are included in the analysis. Anisotropy and increasing penetration rate both will result in a decrease in the skin effect. Any horizontal well length greater than the equivalent horizontal length of the cone-shaped damage region will result in a constant cylindrical-shaped damage region, which can be evaluated using Hawkins’ formula.
The cone-shaped damage region will exist at the furtherest end of the horizontal length. The time to transform the cone-shaped damage region to a cylinder is the circulation time after drilling to the total length. This circulation time is determined for the various anisotropy ratios and penetration rates.
A Comprehensive Approach to Formation Damage Diagnosis and Corresponding Stimulation Type and Fluid Selection
Authors: Xiong Hongjie , Holditch Stephen A. 
Published: December 2007

Abstract
This paper describes a comprehensive approach to formation damage diagnosis. Once the cause of formation damage and the location of the damage is known, then one can select the optimum fluid and design the best treatment to remove the damage. Our approach combines the domain knowledge with the best available expertise, then uses new technologies, which include fuzzy logic and an expert system. Our approach first diagnoses the formation damage mechanism, then we determine the treatment method, and finally we select the optimal fluids for the treatment.
Hydraulic Gas Pump: A Discussion of its Power Usage
Authors: Amani Mahmood 
Published: December 2007

Abstract
This paper presents the results of a study that compares the theoretically calculated power consumption of a Hydraulic Gas Pump, rod pumps, and electric submersible pumps. The results indicate that, depending on the flowing bottomhole pressure of a well, a Hydraulic Gas Pump can have lower power costs than a rod pump or a submersible pump.
We present a method for calculating the power cost of a Hydraulic Gas Pump and discuss the relationship of the power cost of this pump to the flowing bottomhole pressure. Several graphs compare the calculated power consumption of a rod pump, submersible pump, and Hydraulic Gas Pump for well depths ranging between 6,000 and 10,000 feet; flowing bottomhole pressure ranging between 500 and 2,000 psi; and production rates of 300 and 500 BLPD.
Development of a Completion Design to Control Screenouts Caused by Multiple Near-Wellbore Fractures
Authors: Stadulis Jerome M. 
Published: December 2007

ABSTRACT
This paper discusses possible explanations, based upon previous studies, for the hypothesis that multiple fractures at the borehole wall may be a common feature of the hydraulic fracturing process. It then uses field examples to show how we concluded that a type of low-concentration screenout common to three fields in Texas and Oklahoma was caused by multiple fractures. Next, it shows how we developed a completion that controls loss of the pad and slurry to multiple fractures. Finally, it discusses some of the implications of our experience for completion design in general. Since the symptoms of the low-concentration screenout have been documented in the literature by other authors and appear to be quite common, our design techniques should be effective in other areas as well.
The completion design combines unoriented, zero-degree-phased, big-hole perforations shot at low density; and small, high-concentration proppant slugs with clean spacer stages pumped very early in the treatment. These strategies were chosen (1) to limit the number of separate fractures that initiate from individual perforations, and (2) to screen out narrow fractures early in the treatment so that more width is developed in the remaining fracture(s). We have used these techniques to increase overall sand/fluid ratios (including the pad) from about 2.3 ppg (Ibm added per gal fluid) to over 8 ppg, on modestly-sized treatments up to 200,000 Ibm.
Modeling of Undersaturated Coal Seam Gas Reservoirs
Authors: Kohier Timothy E. , Ertekin Turgay 
Published: December 2007

ABSTRACT
Earlier numerical models for coal seam gas reservoirs assume that at initial reservoir conditions coal is either on or above the sorption isotherm, i.e., either equilibrium or saturated conditions prevail. Therefore, when undersaturated conditions exist, implementation of these models does not capture the physics of the problem accurately. In this paper, simple algorithmic procedures are proposed which allow the model to cross the isotherm between saturated and undersaturated regions during computations.
Several examples which demonstrate the successful application of the proposed algorithms are presented. Implementation of the switching mechanisms to existing coalbed simulators is straightforward and should significantly enhance their applications.
Using Low Density Tracers to Evaluate Acid Treatment Diversion
Authors: Reid Mark , Holcomb David , Waak Kyle A. 
Published: December 2007

Abstract
Utilizing a newly developed low density zero wash tracer carrier (1.1 - 1.5 gm/cc), acidizing treatments performed across large gross intervals consisting of thinly laminated carbonate/sandstone reservoirs have been more accurately diagnosed with respect to placement efficiency. Multi-isotope tracer in combination with spectral gamma ray logs are used to evaluate and optimize acid treatments involving various diverting processes (i.e., rock salt/benzoic acid; ball sealers). Acid diverter treatments are evaluated using multi-tracer spectral gamma ray logs and subsequent efficiencies shown. A new low density tracer carrier that allows more effective, safer transport and placement of the isotopes was used and significantly improved the log interpretation. Example case histories of acid treatments evaluated using the new low density tracer carrier will be presented for treatments done in Utah, U.S.A.
Acid treatments performed in long multi-perforated intervals using various diverting techniques were shown to have different coverage distribution than expected or indicated by treatment pressures. A new low density tracer carrier provides a clearer log definition where multi-isotopes are used to define acid stage and diverter stage distribution.

Applications
Acid treatment diversion efficiency and effectiveness can be more accurately diagnosed with the new low density solid isotope carrier instead of previously used highly adsorptive liquid tracers. Actual treatment placement can be more specifically defined without problems caused by wellbore contamination using liquid tracers. Log definition was improved as well by using the new low density solid, as opposed to liquid tracers.
A new tracer carrier to allow improved evaluation of acid treatment placement using diverters has been used and demonstrated to be more reliable than other solid or liquid carriers.
A low density, specially sized, ceramic material was developed and used to contain multi-isotopes: Ir-192, Sc-46, and Sb-124, so they could be transported more easily in acid treatments to evaluate both stage and diverter placement efficiency. This carrier helps eliminate loss of isotope to tubular surfaces.
Testing And Practically Applying Pump-Off Controllers In A Waterflood
Authors: Eckel Andy C. , Abels Harold P. , Merritt Ross A. 
Published: December 2007

Abstract
During the course of this study, many lessons have been learned regarding the practical, efficient use of pump-off controllers. Most were the result of effective field testing and effective communication with lease operators.
The purpose of this paper is to share the learnings about pilot testing, well selection, equipment selection and lease operator buy-in. By sharing these learnings, the authors hope to ensure that future applications of pump-off controllers are practically planned and efficiently installed - thus maximizing their economic potential.
Numerous papers have espoused the economic benefits of pump-off controllers. Most of the results and recommendations provided herein are qualitative in nature. Quantitative results are provided where applicable.
A Unique Method of Evaluating Stimulation Effectiveness in Production Damaged Slotted Liners
Authors: Wood William D. , McKeon Dan 
Published: December 2007

ABSTRACT
After years of service in steamflood and cyclically steamed reservoirs, slotted liners tend to become clogged with migrating formation material and heavy asphaltene deposits1. These deposits seriously restrict inflow and typically make the wells economically unproductive. Acid wash jobs performed through coiled tubing jet wash tools have been found to be extremely effective as a damage removal technique. This paper describes development, testing and preliminary findings of a test vessel which can mechanically isolate small sections of damaged slotted liners and evaluate the effectiveness of different stimulation scenarios.
Hydratable Shales and the Salinity High Enigma
Authors: Overton Harold L. , Zanier Aldo M. 
Published: December 2007

Abstract
Water salinity in marine formations is shown to be a result of compaction and diffusion in the earth. Overpressure, rock stress and salinity variations are all related to drilling depth and geologic time by equations of the following type.
c'(-P) 2c = c 10 + AD sin (Z)(1-e- Dt).W Wo c
The constants A and are determined by boundary conditions and cWo and c' are related to geologic time. Zc is the depth below critical compaction. Whenever the age of a section is known, all of the parameters may be determined from a single well log. When a salt source is not present, the second term disappears or is supplanted by a sink term.
The deep drilling environment is dominated by the compaction and diffusion mechanisms. The occurrence of gas and condensate is predominantly a result of the salinity contrasts shown by these mechanisms, whenever mechanical trapping is present. The phase behavior of shales and their connate phase behavior of shales and their connate fluids, as well as hydrocarbon fluids, is related to the compaction and diffusion phenomena. phenomena
Introduction
The salinity principle has shown that rock stress, hydraulic pressure and the NaCl content of formation waters are macroscopically related. Whenever compaction stress reduces the water fraction of shales, the water in equilibrium between sands and shales becomes more concentrated. This happens consistently in areas with large shale fractions (greater than 50 percent), down to about 10,000-ft depth. The profile of salinity vs depth is very uniform in profile of salinity vs depth is very uniform in areas such as the Gulf Coast, so long as overburden is the dominant variable in the Tertiary. The gradient is of such reliability that the geologic age of the rock column between 3,000 to 8,000 ft can be determined about 75 percent of the time, using the following equation;
-10 558c = 70 × 10 (, years). .
Care must be taken, however, that anomalous gradients such as exist around faults, unconformities and rising domes- are first delineated.
Although the salinity gradients are consistent in marine sands surrounded by massive shales, the maximum depth at which the salinity continues to increase is a more complicated entity. Figs. 1 and 2 show that the salinity maximum may exist at widely separated depths. This is somewhat in accord with the top of overpressure, which varies independently of depth of burial (and most geological) factors occurring at the time of deposition).
Efforts to Improve the Profitability of the Huizhou Fields
Authors: Chou Clement K. , Liu Defu , Zhai LingShen , Duan Chenggang 
Published: December 2007

ABSTRACT
The Huizhou 21 — 1 oil field is one of the first offshore oil fields to be developed in the South China Sea. After start—up of production from HZ/21 — 1 in 1990, four adjacent oil fields have been developed and tied into the original infrastructure. The Huizhou Fields were developed and are operated by a joint venture between China Offshore Oil Nanhai East Corporation (CONHE) and ACT Operators Group, which is jointly owned by three Western oil companies ( A gip, Chevron, Texaco).
Even though oil prices have been much lower than originally forecasted, ACT and CONHE have been able to mitigate the impact of lower oil prices on the financial performance of the Huizhou Fields. This is due to better — than — expected reservoir performance, continuous efforts to update and improve the development plan, and cost—effective integration of new fields into the existing infrastructure. This case study describes how the development plan has evolved and the continuous learning process that CONHE and ACT went through to optimize economic benefit.
Commercial Test of Polymer Flooding in Daqing Oil Field Daqing petroleum Administrative Bureau
Authors: Wang Demin , Zhang Jingcun , Meng Fanru , Liu Heng , Li Lin , Han Bohui , Qi Lianqing 
Published: December 2007

Wang Demin, SPE Member, Zhang Jingcun, Meng Fanru, Liu Heng, Li Lin, Han Bohui, Qi Lianqing

Abstract
Commercial pilot test of polymer flooding in Daqing oil field has been conducted for nearly two years, this paper summarizes the operating procedures and its initial results. Although this test is far from completion, it is successful according to the analysis of the obtained data which is marked by dramatic decrease of watercut of oil wells, increase of oil production by times, and accordance of the production behaviour with the predicted value on the whole. This test provides excellent prospects for large scale polymer flooding in Daqing oil field.

Introduction
Daqing oil field is a heterogeneous sandstone reservoir formed by "fluvial delta system", and is characterized by low reservoir temperature, low salinity of formation water and medium viscosity of crude oil, which are favourable geological characteristics for polymer flooding.
Four small scale polymer flooding pilot tests have been conducted in Daqing oil field from 1972 to 1993, and have obtained relatively good results, recovery rate was increased by more than 10%, and incremental oil for each ton of polymer was more than 150 tons.
For many years, polymer screening, polymer degradation and core flooding by polymer have been studied in the laboratory, which have provided theoretical basis for pilot tests.
To prove the polymer flooding result under condition of current well pattern and well spacing of the oil field, which is "large well spacing and many well groups", and to provide practical basis for commercial polymer flooding, preparation for this commercial test began to be made from 1990.
Polymer flooding was started in January 1993, and the test is presently under way.

RESERVOIR DESCRIPTION AND RESIDUAL OIL DISTRIBUTION
The test area is located in the northern part of Saertu oil field and the test layers are Pu l (Fig. 1). This areal was put into development by line well pattern water injection in 1963. From the end of 1990 to the beginning of 1991, 50 new wells were drilled to conduct this commercial test, consisting 25 five-spot area well patterns with an injection production well spacing of about 250 m. There are 61 production and injection wells together in the test area, among them 25 are injection wells (including one original injection well and three converted injection wells), 36 are production wells (including eight original production wells).
P. 127
Alkaline-Surfactant-Polymer Combination Flooding For Improving Recovery of the Oil with High Acid Value
Authors: Wanchao Song , Chengzhi Yang , Dakuang Han , Zhijian Qu , Baoyu Wang , Wenluo Jia 
Published: December 2007

ABSTRACT
Study in this paper, alkaline-surfactant-polymer combination system (ASP) as a flooding agent, is a new EOR technology aimed at oil with high acid value. Study has been proved that flooding system's rheology and IFT between flooding system and oil with high acid value are key factors effecting oil recovery. Formation of petroleum carboxylic soap from reaction of alkaline with organic acid in oil, petroleum sulfonate sodium and tritron system (OP-10) added in and their combination effect result ultra-low IFT even at very low surfactant concentration (transient IFT less than 10−4mN/m, balanced EFT as low as 10−3−10−2mN/m). Appropriate concentration of partly hydrolyzed Polyacrylamide (PAM) could significantly increase viscosity of flooding agent. Combination effect of both greatly increased capillary number which restricts residual saturation. Presence of alkaline obviously decreased surfactant loss in porous media. Oil recovery of physic simulation augmented by over 16% (OOIP). Net oil augmentation of 20667.7t has been obtained from a pilot area in an almost abandoned water flooding field of Gudong, Shandong Province. Oil recovery from central area increased by 13.4%.