bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improving the Sulfate Resistance Performance of API cement Class A upon Appropriate Slurry Design
Authors: Morales Marcela , Morris Walter , Criado Marcelo A. , Robles Jorge , Bianchi Gustavo 
Published: December 2007

Abstract
Class A cement has been used for cementing surface casings and shallowwells. API Specification 10A classifies the well cements into three categories, ordinary, moderate and high sulfate resistant, depending primarily on theamount of tricalcium aluminate (C3A) present in the clinker. Cementclass A (ordinary) presents no C 3A restrictions. On the other hand, moderate and high sulfate resistant cements should contain less than 8 and 3 %C3A respectively.
Under certain conditions, sulfate ions will chemically combine withtricalcium aluminate giving rise to an expansive reaction that can cause cementdistress. This process depends on cement permeability and environmenttemperature. Several research studies conducted in this field have proven thatthe degradation process decreases as temperature increases and can becontrolled lowering the cement permeability.
The purpose of this study is to analyze the sulfate attack mechanism atseveral bottom hole conditions in order to ensure an appropriate well isolationdurability performance using cement class A. Specimens prepared with APIcements class A and G were exposed to solutions containing sulfatesconcentrations ranging from 0 to 30000 ppm and temperatures of 89.6 and 183.2°F (32 and 84 °C). The specimen 's length and weight variation was evaluatedperiodically. The presence of expansive phases (ettringite) was detected bymeans of SEM and EDAX analysis. A model to predict the cement degradationprocess due to sulfates attack is proposed.
The cement specimens (A and G) showed no significant expansion during thefirst 240 days of exposure, however growth of secondary ettringite in cementpores was detected by SEM analysis. The sulfate degradation process requires acertain incubation period before the cement pores get completely filled withettringite. The use of pore blocking additives increases the sulfate resistanceof cement class A, ensuring appropriate performance and durability.
Design of High Toughness Cement for Effective Long Lasting Well Isolations
Authors: Morris Walter , Criado Marcelo A. , Robles Jorge , Bianchi Gustavo 
Published: December 2007

AbstractDuring the well service life the cement isolation is exposed to extreme conditions that can cause its premature failure. Certain well completion operation as perforating and hydraulic fracturing, the changes in temperature and pressure during secondary recovery or the mechanical stress originated by formation displacements may cause severe damage to the cement isolation.The mechanical properties (compressive and tensile strength, toughness, Young modulus and Poisson ratio) of different cements were evaluated in order to establish their best service performance. Typical slurry designs were tested focusing the attention on the effect of certain additives such as latex, fibers and other polymers used as fluid loss control or dispersants.The cement mechanical properties were determined according to ASTM and API standard test methods. The cement toughness was evaluated following the API RP 43 standard for testing well perforators.The experimental results show that the mechanical properties of cement are strongly dependant on the particular additives used when preparing the slurry. Even when cement with no admixtures presents high compressive strength it also shows a fragile behavior with limited strain and low toughness. The use of latex improves the cement elastic behavior although it does not better its impact resistance. On the other hand, the addition of polymer fibers improves the cement toughness and its elastic behavior. As it was demonstrated by well testing profiles run before and after perforating, the addition of fibers improves the cement performance when exposed to the different events that may damage the isolation during the well service life.
Acoustic Signal Analysis for Sand Detection in Wells with Changing Fluid Profiles
Authors: Allahar I. A. 
Published: December 2007

Abstract
Sand production can be a severe problem in the East Coast oil and gas fields of Trinidad. Geologically young formations in this region exhibit little to no natural cementation forming very weak unconsolidated sandstones that often lead to sand production. With the increasing drive to increase production rates, the accepted draw down limits for these reservoirs may be tested. As a result surface monitoring and early detection of sand production has become extremely important in providing further assurance to mitigating potential incidents due to sand production resulting from excessive draw downs.
For this project, data collected from thirty acoustic sand -detector calibration trials done in three fields offshore East Coast Trinidad, was analysed to investigate the accuracy of the sand detector in predicting sand concentrations in different fluid profiles. From this study, a simple model is being proposed which can predict sand concentration for sand particles ranging between 30 to 120 microns at any given fluid profile using an acoustic sand detector. This model may be used in the absence of a calibration plot and when the flow profile of a well is changing, to accurately predict sand concentration. The results from this project can provide the operator with greater assurance when optimising production rates, especially in wells that have a tendency to produce sand.
Hydrocarbon/Solvent Treatment for Inhibiting Paraffin and Suspending Asphaltenes in Oil Wells
Authors: Campbell Gale J. , Griffin John M. 
Published: December 2007

Abstract
A blend of polymeric hydrocarbons within a solvent solution (HIS-polymer) has been developed (patent pending) that enhances the flow capacity of oil wells adversely effected by (a) high viscosity, (b) tubular and rock matrix plugging due to precipitation of paraffin and asphaltene.
Theoretical mechanisms contributing to observed flow increase following application of HIS-polymer in field conditions include (a) preferential wetting of matrix surfaces by HIS-polymer, (b) reduction of relative permeability to water and increase of relative permeability to oil, (c) stabilizing interfacial tension, (d) generation of heat which disperses paraffin and asphaltenes sufficiently for them to enter flow stream, (e) inhibition of paraffin precipitation, (f) deasphalting heavy crudes through solvent action, (g) dispersing and inhibiting the onset of asphaltene precipitation.
Long-term benefit of treatment (exceeding 9 months) is explained by preference for polymeric hydrocarbon to wet previously water-wet matrix. Verification of same is reported using dual-drop-dual-crystal technique in which a 500 ppm concentration of HIS-polymer was observed to convert both a water-wet quartz and calcite to a polymeric hydrocarbon-wet surface.
Field treatment by bullheading through tubing into formation and over displacing with diesel or lease crude is reported. This treatment was for a 15° API oil in eastern Venezuela and resulted in a three-fold production increase from 104 barrels of oil per day (BOPD); production was sustained for an excess of 60 days. Tripling of production in a west Texas stripper well is also included. The HIS-polymer benefits operators by replacing diluents that have been historically used to decrease pressure of heavy oil laden flowlines.
Gas Flood-Flow Pattern Evaluation: A Successful Interwell Field Study
Authors: Mercado Modesto , Perez Carlos E. , Asadi Mahmoud , Casas David R. 
Published: December 2007

Abstract
A successful reservoir flood depends on a properly designed injection/production pattern. Knowledge of the flow pattern within a reservoir leads to a better design of the injection pattern, which in turn enhances overall recovery. To achieve this goal an interwell tracer program was used to characterize the flow stream within the current injection/production pattern of the central part of the Mesozoic Chiapas-Tapasco Basin. The field includes one injector and four producers. Due to production, the average reservoir pressure fell and approached the dew point at reservoir conditions. Natural gas was injected to maintain reservoir pressure and optimize condensate production. A chemical interwell tracer was also injected to detect and evaluate the magnitude of any communication between the injection and production wells and to track the areal flow pattern within the field. The study was designed for 18 months and commenced in December 2000. The results from the sample analyses provided information on the magnitude of highly permeable channels between the injector and producers as well as flow pattern within the field. Furthermore, the results provided valuable information on breakthrough time, which in turn shall lead to a more efficient gas injection design.
Pore-Level Observation of Gravity Assisted Tertiary Gas-Injection Processes
Authors: Ren W. , Bentsen R. , Cunha L. B. 
Published: December 2007

Abstract
In water drive oil reservoirs, more than half of the initial oil in place is trapped in the water-contacted zone after natural water influx or waterflooding. Gas injection into such reservoirs, with the assistance of gravity, interfacial tension and oil film flow, can cause the displacement of excess water and the redistribution of reservoir fluids in the pore space. As the result of such fluid redistribution, most of the residual oil can be recovered. Moreover, a second water flood following the gas injection can recover the oil in a shorter period of time.
Gravity assisted tertiary gas injection processes include the Double Displacement Process (DDP) and the Second Contact Water Displacement Process (SCWD). The DDP consists of injecting gas into waterflooded oil zones. The SCWD process consists of submitting these gas-flooded zones to a new water displacement process. In this work, the double displacement process (DDP) and the second contact water displacement (SCWD) process were conducted in a transparent sand-pack micromodel, and a pore-level observation was performed to investigate the microscopic mechanisms of the two processes.
Observation of the two processes confirmed that the oil films play a very important role in achieving high recovery efficiencies in the DDP. The oil film was seen clearly. Such observation showed also that oil flowing through oil films and layers was driven not only by its own weight, but also by the increasing volume of the gas. In the SCWD process, trapped gas reduces the possibility of the residual oil being trapped in the center of the pores. Consequently, residual oil can be recovered quickly by a second water flood. Therefore, the SCWD process is suitable to apply in situations where the source of gas is not sufficient, and where the formation has a high irreducible gas saturation.
An Integrated Long-Term Solution for Migratory Fines Damage
Authors: Hibbeler Jeff , Garcia Thomas , Chavez Nelson 
Published: December 2007

Abstract
Mobilization of fines can severely damage a well's productivity and is one of the more costly sources of well damage identified to date. Termed fines migration, the phenomenon is complex but governed largely by mineralogy, permeability, salinity and pH changes as well as drag forces created by flow velocity, turbulence and fluid viscosity1–10.
Over the years various mixtures containing hydrogen fluoride (HF) acid or its precursors have been used to dissolve fines and increase permeability in sandstones. However, it has been noted in considerable prior literature11–21 that these treatments can result in relatively shallow penetration due to the rapid spending of HF. Frequently the treatment is limited to a few inches in the formation beyond the wellbore region and this allows future fines re-invasion into the near well bore. Also fines acidizing alone is merely treating the symptom rather than the underlying cause and it can be assumed that the duration of the benefit is limited to how long it takes for fines to be released and begin to restrict flow again. Thus, a concern for operators is the fact that the benefit of HF acid treatments for fines can be short-lived. Other treatments were developed to fix fines in place21–22 however these systems have not been widely used.
The optimum treatment for fines would integrate techniques to dissolve fines, enlarge pore-throat size to diminish near wellbore particle bridging, and finally to "lock-in-place" those fines that are not removed by the treatment. Furthermore, a long-term, integrated solution must address the mechanism of fines migration so that a comprehensive approach to the problem may be employed.
This paper reviews fines damage mechanisms and presents a fluid system to correct fines damage and prevent fines migration in a single treatment, while keeping acidizing risk at a minimum. The new system uses an organo-phosphonic acid (HV) to generate and moderate HF for deep penetration and an organosilane fines-fixing agent (FFA).
Sensitivity Analysis on the Two-Phase Flow Properties in a Turbidite Reservoir
Authors: Di Pierro Esteban , Stephen Karl D. , McDougall Steven R. M. , Pickup Gillian E. 
Published: December 2007

Abstract
We need to know saturation dependent relative permeability and capillary pressure functions for the reservoir rocks in order to be able to carry out flow simulation successfully. Both of these properties depend on the wettability, which is acknowledged as playing an important role in fluid flow.
We have carried out a sensitivity study of the two-phase flow properties on the production from a turbidite field, starting with network modelling to simulate two-phase flow at the pore scale. A new method has been used to "anchor" network model parameters to existing (drainage) capillary pressure curves. The wettability was varied systematically, and a range of corresponding relative permeability and capillary pressure curves were generated. These curves were then used in flow simulations of a sector of the turbidite reservoir.
Results show that it is very important to consider uncertainties in the two-phase flow parameters because they have a significant effect on recovery.
Horizontal Well Geosteering: The Experience in a Giant Campos Basin Deep-Water Field
Authors: Coutinho M. R. , Abreu C. E. , Braga M. S. , Maciel W. B. 
Published: December 2007

Abstract
Horizontal well geosteering involves careful monitoring of the well during the drilling phase. To this end, relevant geophysical and geological tools are used to build a consistent geological model. Real-time information enables constant updating of this model providing the necessary information for geosteering decisions. These geosteering procedures allow for close control of the well trajectory in the target layer, reducing the risks of redrilling.
Evolution of Drilling Technology in Mature Reservoirs of Lake Maracaibo: Short-Radius Reentries, Horizontal Wells, and Highly Deviated Wells
Authors: Villasmil R. , Segovia G. J. , Valera R. E. , Lopez Ch. , Fernandez A. , Hinestroza D. 
Published: December 2007

Abstract
After 70 years of continuous exploitation in the Bolivar Coast region of Lake Maracaibo, Venezuela (Fig. 1), advanced reservoir depletion is causing drilling problems such as severe loss of circulation, hole instability, and extensive formation damage. In an attempt to optimize drilling performance, several operation practices were implemented through 1997, such as air-, mud-, foam-, and oil-base mud systems, etc., without achieving the expected success. Fig. 1Geographic location.
Because of the challenges of working in these mature fields, the operator and the oilfield services company created a services alliance contract called PRISA (a Spanish acronym for Integrated Drilling and Workover Alliance Services). This paper describes the drilling technologies and best practices used to improve drilling performance in these mature reservoirs, the learning curve evolution, and process improvement. The results included a cost reduction of 12% (in investment cost/barrel), a production increase of 4%, a 58.7% reduction in drilling time, and a drilling cost reduction of 3.6% (Figs. 2 through 3B). In addition, nonproductive time (NPT) has been reduced from 24.1% in 1999 to 3.8% in 2002 (Fig. 4). Fig. 2Drilling time evolution in mature fields in Lake Maracaibo.Fig. 3ADrilling costs evolution in mature fields in Lake Maracaibo.Fig. 3BProduction evolution in mature fields in Lake Maracaibo.Fig. 4NPT evolution in drilling operations in mature fields in Lake Maracaibo.
Stimulation Efforts in Carbonate Gas Reservoir Experiencing Subsidence in Offshore North West Java Field - Indonesia
Authors: Susilo Yoliandri , Rahamanda Zahazny , Wibowo Wahju , Tjahyadi Riza , Silitonga Frans J. , Nasser Iqbal 
Published: December 2007

Abstract
Subsidence and reservoir compaction continues to be significant concern for the oil and gas industry. The decrease of pore pressure during hydrocarbon production (depletion) leads to compaction of the reservoir. When compaction occurs, it changes the porosity and permeability properties of the reservoir rock and can affect recovery efficiency and well productivity. The results of stimulation efforts to improve gas deliverability in carbonate reservoir experiencing subsidence in Offshore North West Java (ONWJ) field are presented here.
The wells in this study were completed in the Parigi Formation, which is a thick carbonate buildup formation with large columns of gas about 250-300 feet thick underlain by aquifer. It has high porosities (32-45%) and good gas permeabilities up to several Darcies with the initial well production were around 20-30 MMSCFD. The continuous production of gas from this shallow, thick and low strength carbonate reservoir has resulted in reservoir compaction, surface subsidence, several well mechanical failures and a sharp production decline (from 15 MMCFD to 2 MMCF). The other impact of declining gas rate that is nearing its critical velocity is causing water condensation that cannot be lifted out of the well; it then accumulates in the wellbore and creates more back pressure on the reservoir.
Treatment efforts, starting from nitrogen kick-off with CT to unload the condense water in the wellbore followed by re-perforation and acidizing job, that were conducted in the first two well have resulted a significant production response. Gas production increases by 4-9 times after the treatment. The previous fear/perception that acidizing would perhaps even worsen the conditions of the reservoir and thus reduce production proved not to be true. These successful treatments have led to stimulation campaigns for other wells in the area.
This paper will also discuss several surveillance projects to monitor and assess the magnitude and progression of surface subsidence, reservoir compaction and wellbore damage in this area.
A Novel Methodology for the Analysis of Well Test Responses in Gas Condensate Reservoirs
Authors: Barrios K. , Stewart G. , Davies D. 
Published: December 2007

Abstract
Single-phase analysis based on pseudopressure has been extensively used in the oil industry to analyse well test data from gas condensate reservoirs. However, the presence of the two-fluid system which forms when the pressure drops below the dew-point requires advanced techniques to derive accurate skin values. This quantity contains contributions from the mechanical, non-Darcy and liquid drop-out components. Many remedial well treatments (acidification, hydraulic fractures, etc) have been designed on such incorrect analysis, the resulting lack of treatment success leading to an unnecessary increase in operational cost. The aim of this study is to develop a full understanding of multiphase flow effects, to establish a systematic methodology using the two-phase pseudopressure function and to obtain accurate results from gas condensate well test analysis.
This work uses the steady-state, two-phase pseudopressure in the same manner as the familiar single-phase pseudopressure analogue.
A 1D compositional simulation model was used to generate the input data for the well test interpretation, special attention being paid to the time step and grid size distribution to avoid numerical truncation errors.
The mechanical skin used varies from negative values (wells with fractures) to positive values (wells with formation damage). A correlation between the skin value obtained from the two-phase pseudopressure analysis and the mechanical skin was derived. This allows the reservoir engineers to make the key discriminations between mechanical skin and liquid drop-out skin.
The approach used here was also extended to generate a general understanding of the production behaviour of condensate production wells e.g. fluid, velocity and relative permeability effects on the resulting pressure drops created by condensate accumulation near to the wellbore. This will find application to well design e.g. the conditions under which horizontal wells can eliminate a condensate bank near to the wellbore can be confidently predicted.
Distribution of Injected Water by Using CGM Method: A Case History in Palogrande-Cebu Field
Authors: Saavedra N. F. , Peralta R. C. , Cobb W. 
Published: December 2007

Abstract
Craig, Geffen and Morse (CGM) Method, one of the most thorough and practical prediction method for waterflooding prediction, was applied to the Palogrande-Cebu Field in Colombia South America to define the vertical distribution of the injected water of a project that has 18 years old. The field has five producing units that had been waterflooded since 1984. The CGM method was adapted to match the actual fluid production rendered confident vertical water distributions and actual water saturation for the different units and for all the producing wells. Methodology was as follows: Analysis of the injection and production curves. For every production well a rigorous analysis of the production curves was compared with the injection curves of the closest injectors. This analysis allowed a selection of the injectors that affected the fluid production of the well in analysis. This step gave a qualitative approach.Injectivity analysis. Logs of water injection distribution were analyzed for all the injectors. This step gave a vertical injection distribution for the five units at the injector but did not give a clue about the areal distribution of the water.CGM method. The CGM was adapted to be able to match the actual fluid production of the field. For each producer, the selected injectors in step 1 were evaluated. Some times it was necessary to include or reject injector wells to get the match of the produced fluids.
The combination of the three steps allowed getting a real view of the areal and vertical water distribution. The above method is been used to get a realistic numerical simulation of the field, since a thorough knowledge of the field has been reached. This paper describes in detail the methodology and the field results for Palogrande-Cebu field.