bluuebunny/crossref_metadata_2025_split huggingface dataset:
Changing the Game of Fluid Placement: Intelligent-Well Intervention on a Trilateral Horizontal Well
Authors: Jacobsen J. R. , Kharrat W. , Noya J. V. 
Published: July 2010

Abstract
Matrix acidizing stimulation in carbonate formations with open hole and multilateral completions presents several challenges to insure an optimum treatment is performed. Each lateral must be accessed to place and clean up the acid treatment. The key objective of the intervention is not only to eliminate as much as possible the damage in the matrix produced by the drilling and completion process, but also trying to connect to high conductive fractures that will maximize the drainage of hydrocarbons out of the formation. In this type of completions, traditional practices are limited to spot stages of fluids (pre-flush, acid, and diversion) in front of the formation without much control over the placement.
This document describes, through a field experience, how new Coiled Tubing (CT) conveyed downhole measurements can assist to overcome the challenges above, enabling more intelligent interventions. An innovative workflow designed to optimize stimulation treatments as they occur was implemented for the first time in Saudi Arabia on a sub-hydrostatic, trilateral horizontal openhole oil producer. The workflow uses as reference formation porosity or permeability logs as well as Distributed Temperature Surveys (DTS) for the evaluation of distribution and fluid temperature responses to decide selective placement of stimulation fluids. A consistent lateral fluid flow distribution from the preflush stages and acid stage treatments in each well's lateral, as well as a bullhead injection test recorded in the main bore, is presented. Selective lateral access was enabled by using an Indexing Flow-activated Bent Sub (IFBS) and confirmed upon entry using a real-time casing collar locator (CCL).
The well began producing at the maximum capacity of the ESP pump used to clean the well after the acid treatment, with results that exceeded expectations, effectively overcoming the high drawdown and low Productivity Index (PI) observed in the well.
This experience demonstrates that innovative downhole measurements in combination with the referred workflow make possible to understand fluid distribution and control fluid placement with Coiled Tubing, unlocking the well production potential. This new technique is proven to be an optimum solution for the type of completions commonly found in Middle East.
Modeling of Multisegmented Thermal Wells in Reservoir Simulation
Authors: Semenova Anna , Livescu Silviu , Durlofsky Louis J. , Aziz Khalid 
Published: July 2010

Abstract
Advanced wells are being used more and more frequently to improve the economics of oil field operations. Such wells can contact larger regions of the reservoir than is possible with standard wells. Because these wells can be very long, pressure drop along the well and temperature effects (in thermal problems) can became quite important. Modeling of advanced wells where thermal effects need to be included is a difficult task, and available models are often limited in their capabilities or are inefficient.
A suitable model should be able to handle complicated well trajectories, heat transfer to and from the well, the hold-up of fluids due to slip between phases, and pressure change due to friction. This paper presents a comprehensive multisegmented well model that includes these features. The model has been implemented in Stanford's General Purpose Research Simulator (GPRS). It calculates both pressure and temperature profiles along the well for standard wells and wells with complicated trajectories. One of the advantages of our model is that both homogeneous (no slip) and drift-flux flow models can be used to determine phase distribution within the well. The hydrocarbon fluids can be described either through a black oil representation or using a general compositional model with an arbitrary number of components. The proposed multisegmented well model was tested with a number of challenging and realistic examples. Our results show that the model is stable and in most cases converges in only a few iterations even with reasonably large time steps. The capabilities of the model are demonstrated using three examples. The first example involves a vertical production well with the fluid represented in terms of six hydrocarbon components and water. For this case we demonstrate the importance of slip between phases. The second example is for a thermal multilateral well with two branches and a fluid with three hydrocarbon components. The third example shows our ability to model phase appearance and disappearance in the wellbore and demonstrates the impact of temperature on oil and gas rates during production.
The Effects of Barium Sulphate Saturation Ratio, Calcium and Magnesium on the Inhibition Efficiency: II Polymeric Scale Inhibitors
Authors: Shaw S. S. , Sorbie K. S. , Boak L. S. 
Published: July 2010

AbstractIn oilfield produced waters, the mineral scaling problem is a "moving target" since the seawater/formation water (SW/FW) mixing ratio is constantly changing. Therefore, for barium sulphate for example, the barite saturation ratio (SR), the yield of barite precipitate and molar ratio of Ca2+/Mg2+ in the produced waters are all evolving over time.This paper describes the effects of saturation ratio (SR) and Ca2+/Mg2+ ratio on barium sulphate inhibition efficiency (IE) of the polymeric scale inhibitors (SI), PPCA (phosphino poly carboxylic acid), MAT (maleic acid terpolymer), and SPPCA (sulphonated PPCA). The behaviour for polymers is compared with similar results for phosphonates reported in Paper I (SPE 130373). IE experiments were carried out for a wide range of SW/FW compositions (i.e. SR and Ca2+/Mg2+ varying). The minimum inhibitor concentration (MIC) levels of these polymeric SIs broadly correlate with the level of barite saturation ratio (SR). When experiments were repeated but the produced brine Ca2+/Mg2+ ratio was fixed, a similar IE trend is maintained. However, using the non-sulphonated polycarboxylate SIs (PPCA and MAT), the base case MICs are lower than the fixed case MICs whereas using SPPCA, the converse is true i.e. the fixed Ca2+/Mg2+ case MIC &lt; base case MIC. We have demonstrated that the high [Ca] in the fixed case tests causes some SI precipitation with brine Ca2+ when PPCA is being evaluated. Sulphonate functional groups on polymeric SI molecules help to prevent such problems encountered with brine Ca2+. Low levels of brine calcium (~500–700ppm) can be very beneficial to the IE performance of PPCA. However, when the [Ca2+] reaches a certain level (~1000ppm+); this causes some precipitation of a Ca_PPCA complex. We show that lower [Ca2+] levels are optimum (~500–700ppm) and we deduce this is why non-sulphonated polycarboxylate SIs PPCA and MAT perform better under base case mixing conditions (lower [Ca2+] mix).
Effective Perforating Design for Matrix Acidizing in Pre-Salt Carbonates
Authors: Filho Hercilio , William A. , Gabriel E. , Junk E. , Boucher A. , Baumann C. E. 
Published: July 2010

Abstract
Engineers face many challenges in deciding how to complete Pre-Salt, carbonate reservoirs offshore Brazil. These challenges include: predicting reservoir performance; evaluating well productivity; determining the best completion design strategy; and finally, determining the best matrix stimulation techniques. Matrix acidizing is a common approach to enhance production from carbonate reservoirs. Well defined wormholes bypass near wellbore damage and provide greater reservoir productivity. Poorly known microbial carbonate can impact acidizing diversion and effectiveness in such rock. Optimizing the stimulation process by perforating and acidizing in the correct way in such high-cost projects is a crucial issue for improved well productivity.
This paper discusses how effective perforation design positively impacted the evaluation (Well Testing) and acidizing efficiency in such formations. Results from pre and post matrix acidizing PLT logs and transient analysis from downhole and surface well test data demonstrates perforating design efficiency and how it aides in diverting acid over the entire interval compared to another well in the same field.
Breaking Oil Recovery Limit in Malaysian Thin Oil Rim Reservoirs: Force Balance Revisited
Authors: Razak Ezzam A. , Chan Keng Seng , Darman Nasir 
Published: July 2010

Abstract
The goal of an oil field development project is to accelerate the hydrocarbon production and optimize the recovery at the lowest cost. For a thin oil rim reservoir with a large gas cap on top and a strong aquifer below, achieving such goal can be very challenging since recovery of both oil and gas needs to be optimized. A successful project may entail plan first to accelerate the oil production with re-injection of the produced gas at the gas cap, maximizing the oil recovery prior to the start-up of the gas cap blow-down (Ref. 1–2).
The maximum oil recovery factor achievable in thin oil rim reservoirs was evaluated for a Malaysian thin oil rim reservoir based on dynamic flow properties. The force balance between the gas cap expansion, aquifer expansion and viscous withdrawal (volumetric fluid production) was demonstrated by showing the model simulated water-oil and gas-oil contact movement. The understanding of the force balance progressively guided the field development project team to selectively re-activate some of the idle wells, to selectively place new additional infill horizontal wells, and to plan selective water and gas injection in key reservoir sectors.
In this paper, the impact of changing force balance on oil recovery by increasing viscous withdrawal with increasing idle well re-activation and infill horizontal well drilling at their respective optimum produced gas re-injection was reported. This effort showed a potential of improving the current recovery factor from 35% up to 48%, at and above the estimated theoretical maximum oil recovery efficiency.
Effects of Sulphide Scales (PbS, ZnS & FeS) on BaSO4 Crystal Growth and Dissolution
Authors: Okocha C. , Sorbie K. S. 
Published: July 2010

Abstract
Sulphide scales (iron sulphide, FeS, zinc sulphide, ZnS, and lead sulphide, PbS) are occurring more commonly in many water producers and these deposits and colloids may lead to various production problems. In addition to being a problem, the presence of these sulphides also affects barium sulphate deposition. The resulting crystal distortions of the barite may play an important role in either enhancing or retarding the barite scale inhibition itself. This study investigates the effects that sulphide scales have on the crystal lattice of barite during its formation. These effects vary based on the type of sulphide scale which co-precipitates with the barite scale. FeS was found to have the most profound effect on the barite crystal by causing severe crystal distortions and it also adheres more strongly to the outer layers of the barite. It is also found that the FeS/barite scales are also the easiest of the mixed scales to inhibit. The ZnS and PbS scales did not cause significant crystal distortion of barite compared to the FeS and they were also the hardest mixed scales to inhibit. The effects of generic scale inhibitors (DETPMP and PPCA) on the barite crystal in the presence of sulphide scales were also studied and several interesting findings are noted. The experiments described were carried out using the static bottle tests and crystal morphology was monitored using Environmental Scanning Electron Microscope (ESEM) techniques. Better understanding of the effects of FeS, ZnS, and PbS on harder mineral scales such as barite will help in the design and application of scale inhibitors for mixed scaling systems which occur quite regularly in the field as well as in designing downhole squeeze treatments.
Case Study: Shallow Surface Casing Corrosion Mitigation Evaluation
Authors: Blakney R. G. , Loveland M. J. , Klein P. 
Published: July 2010

Abstract
Shallow surface casing failures have occurred in some wells in the Kuparuk oil field located on the North Slope of Alaska. A previous investigation into these failures has shown that they are caused by shallow external corrosion of the surface casing within the conductor annulus. The corrosion is believed to be caused by the presence of oxygenated surface water in the annulus and exacerbated by the extremely corrosive environment created when this water mixes with the ion-rich cement.
To combat this issue a field wide corrosion mitigation program began in 2006. The program focuses on injecting a corrosion inhibiting compound into the outer most annulus. At the time of this paper, 870 out of 1270 wells have had the mitigation completed. The goal of this compound is to coat the pipe and stop the influx of water into the annulus; without the water influx the corrosion should be reduced.
Concurrent with the mitigation program, a memory logging tool was used to monitor corrosion rates. This tool surveys variations in pipe metal thickness by measuring variation is velocity and amplitude of alternating magnetic waves. The log results display total metal volume by calibrating the tool at a depth that is assumed to be undamaged. The accuracy of this tool was verified for specific casing configurations on 14 wells that were excavated and inspected after logging. Since then, this log has been run several months prior to, at the time of, and several months after injecting the corrosion inhibitor into the annulus on various wells.
Using the data available from the logs and surface casing failures, the effectiveness of the corrosion mitigation program was evaluated. The main focus of this paper will be the methodology and conclusions obtained from the evaluation.
This paper will: Review the cause of shallow surface casing corrosion.Discuss current mitigation methods for reducing this corrosion.Detail how these methods vary based on well head design.Discuss the logging tool, its limitations, and how it was used for evaluation.Summarize the results of the evaluation.Discuss recommendations for improving the effectiveness of corrosion mitigation project on remaining wells.Outline the future of the corrosion mitigation project.
Effects of Oil Compressibility on Production Performance of Fractured Reservoirs Evaluated by Streamline Dual-Porosity Simulation
Authors: Tanaka Shusei , Arihara Norio , Al-Marhoun Muhammad 
Published: July 2010

Abstract
As naturally fractured reservoirs (NFR) present wide ranges of geological characteristics and complex flow mechanisms between matrix and fracture, reservoir simulation is highly necessary to properly evaluate production performance. The production performance depends on fracture distributions and matrix/fracture properties as well as on fluid properties. We studied by simulation particularly about effects of oil compressibility below bubble-point pressure on production performance. Also evaluated was how the compressibility effects vary with different fracture spacing that is generally uncertain even in a production stage and should be characterized by simulation.
We first developed and validated a 3-phase 3-dimensional dual-porosity model with the streamline method. The fluid compressibility is a primary parameter that directly affects the reservoir performance. We accounted for compressibility effects with the total compressibility in the 3-D pressure equations, and with the effective density in the 1-D flow equations along streamlines. A flash-calculation algorithm was incorporated to treat the gas and oil phases correctly. We also considered dissolved gas, capillary pressure and gravity
The oil and gas compressibility definitions presented by Perrine, that have been being used conventionally, show a physical inconsistency such that oil compressibility below the bubble-point pressure increases with the increase of density, and that the mass of gas phase remains constant with changing pressures below the bubble-point pressure. To correct those, new derivation based on the basic compressibility definition was introduced.
With constant water-injection and liquid production rates in a 5-spot well pattern, simulation results using the new and conventional compressibility formulation were compared for different fracture and fluid properties such as shape factor and solution gas-oil ratio. With the new compressibility, we obtained slower declines of the reservoir pressure, higher oil- production rates, lower water-production rates, and slower increases of production GOR. Differences between the results with the new and conventional compressibility are augmented as the fracture spacing decreases.
Alkyl Polyglycoside/1-naphthol Formulations with Ultra-low Interfacial Tensions Against N-octane for Enhanced Oil Recovery
Authors: Iglauer Stefan , Wu Yongfu , Shuler Patrick , Tang Yongchun , Goddard William 
Published: July 2010

Abstract
We present Alkyl polyglycoside (APG)/1-naphthol formulations which show ultra-low interfacial tensions (IFT) against n-octane. We demonstrate that 1-naphthol is very efficient as a cosolvent in terms of reducing IFT. These formulations are therefore potentially suitable as agents for enhanced oil recovery (EOR). An increasing APG concentration strongly increased viscosity, and the formulations showed shear-thinning behavior. In a coreflood EOR test we showed that this type of formulation significantly increased oil production.
Sealing Casing Leaks through the Remote Deployment of Discrete Particles
Authors: Loveland M. J. , Klein P. , Ryan N. J. , Bowie C. 
Published: July 2010

Abstract
An outer casing leak can be a significant well integrity issue, primarily due to the inability to easily access the leak site for intervention. Recent outer casing failures caused by external corrosion on some wells in the Kuparuk Field of Alaska prompted research for a non-invasive repair method to delay or negate the need for a rig workover. Limited options for downhole access on outer concentric casing strings have an impact on the ability to define the leak in terms of location, size and shape, and consequently the ability to effect a seal of the casing.
The Platelet® technology discussed in this paper is an innovative means of sealing leaks which involves the remote injection of discrete particles into a well which are then carried to the leak site in the fluid flow. When the platelets reach the vicinity of the leak, fluid forces entrain them into the leak and hold them against the casing wall thus facilitating a seal allowing the well to be returned to service.
Previously proven for applications in subsea pipelines, platelet technology over the last 12 months has successfully been developed for downhole use. In January 2009, specifically engineered platelets were deployed into well annuli for the first time.
Two case studies will be presented where the technology has been used in the Kuparuk field in Alaska. In the first instance a ¼” corrosion induced hole in the surface casing at a depth of 126 ft was sealed with a single platelet by a deployment from surface into the outer annulus. The well was initially leaking at a rate of 0.5 bpm and subsequently passed an 1800 psi mechanical integrity test. The second study will review a seal of a 0.26 bpm leak at 30 ft depth which eventually gave out.
The paper will review the front end engineering development, the well site deployment, and lessons learned. The paper concludes by demonstrating the successful use of the platelet technology for sealing annulus leaks and how the technology has successfully postponed or negated the need for a rig workover to repair a surface casing leak. The results from this study have provided valuable insight into the behavior of the platelets in the fluid flow before entrainment and the behavior in the leak after entrainment.
Biot Critical Frequency Applied as Common Friction Factor for Pore Collapse and Failure of Chalk with Different Pore Fluids and Temperatures
Authors: Andreassen Katrine Alling , Fabricius Ida Lykke , Foged Niels Nielsen 
Published: July 2010

Abstract
A fluid effect towards higher strengths for oil saturated chalk compared to water saturated chalk has previously been identified and labeled the water weakening phenomenon, but has not been further characterized physically until now. The hypothesis of this paper is that the Biot critical frequency can be used to explain this behavior on the pore scale and be extrapolated to the macroscale failure and pore collapse properties. A large set of previously published laboratory test results on chalk was collected. The data spans three different chalk types which were tested at temperatures from 20°C to 130°C with the following pore fluids besides dry chalk: fresh water, synthetic seawater of different chemical compositions, methanol, glycol, formamide, decane and crude oil of varying viscosity.
The Biot critical frequency determines the transition from where an applied sound velocity is dominated by viscous forces to where it is dominated by inertial forces, i.e. when the pore fluid motion lags behind the applied frequency. It is therefore a measure of the internal surface friction between solid and fluid and is interpreted as a friction factor. The Biot critical frequency incorporates the porosity, permeability, fluid density and fluid viscosity, where the latter is highly temperature dependent. All these parameters are usually determined during laboratory tests and the fluid viscosity and density may be found in tabulated references. Besides the fluid effect there is an effect from the applied strain or stress rate on both the strength and yield properties. This phenomenon couples with the critical frequency through the use of a previously published study on the rate dependence.
The data show that the Biot critical frequency can be used as a common friction factor and is useful in combining laboratory results. It is also inferred that the observed water weakening phenomenon may be attributed to the friction between solid and fluid. The scope for the applicability of the Biot critical frequency as a friction factor is in analysis of the compaction of chalk fields where the effect of different fluids and temperatures is relevant.