bluuebunny/crossref_metadata_2025_split huggingface dataset:
Extending the Applicability of Chemical EOR in High Salinity, High Temperature & Fractured Carbonate Reservoir Through Viscoelastic Surfactants
Authors: Azad M. S. , Sultan A. S 
Published: June 2014

Abstract
Carbonate reservoirs possess the greatest challenge for chemical EOR methods. The challenges limiting the applicability of chemical EOR in carbonate reservoirs are the harsh reservoir conditions and the presence of fractures. Harsh conditions include high salinity, hardness and temperature. These conditions make most of the conventional surfactants and polymers ineffective. Fractures in carbonate reservoir provide the easy conduit for injected slugs to break through the production wells, thereby reducing the sweep efficiency drastically. Thus the carbonate reservoirs are not the best candidate for chemical EOR methods.
Viscoelastic surfactant (VES) is the self-assembling surfactant that contributes to displacement and sweep efficiency through the formation of wormlike micelles (WLM). WLM can generate higher viscosity especially at the harsh conditions. The positive impact of VES towards salinity, hardness and temperature could favor its applicability as an EOR fluid. Elastic nature of VES could block the fractures. Three different Viscoelastic surfactants (Ethomin, Armovis and Aquadat) are screened based on WLM growth and IFT. The optimum VES is chosen then. The optimum VES is studied at various concentrations. Surfactants and polymers are added to VES forming S/VES and VES/P system.
High Viscosity meant for mobility control and low IFT meant for oil mobilization are the two important parameters which any formulation in chemical EOR is desired for. Hence, ViscosistyIFT ratio of VES, S/VES and VES/P systems are studied individually with sea water of 57000 ppm at the temperature of 70°C. The potential formulation is reported. The potential of VES as the diversion fluid is also studied.
Results indicated that Armovis could endure the harsh conditions among the three VES studied. VES system performs better followed by VES/P. VES can be a potential diversion agent.
Water – Chemical Treatment, Management and Cost
Authors: Wiggett Adrian J. 
Published: June 2014

Abstract
Recycling produced water for re-use in gas and oil fields for hydraulic fracturing and re-injection to maintain reservoir pressure is becoming increasingly important due to the scarcity of this natural resource. This is especially the case when these activities are not near a readily available source of ‘free water’ such as seawater or an aquifer.
We explore ways to use water management to lower Operational Expenditure OPEX overall by eliminating fresh water sourcing, transportation, storage and its treatment as well as the storage, transportation, treatment and disposal of produced or flow-back water.
The water management approach enables operators to re-use produced waters in hydraulic fracturing fluids. Pre-treatment testing and analysis characterizes the chemistry of the water to ensure an effective fracturing fluid design and to determine the appropriate water treatment solution for every application. By using a comprehensive water treatment suite of technologies, we demonstrate that virtually any oilfield water can be treated. Post-treatment testing confirms the water meets the customer's specific requirements.
Integrating water management service technical expertise with water chemistry and chemical treatments maximizes hydrocarbon production, minimizes reservoir damage, and reduces the costs of fresh water sourcing by as much as 90%. The techniques also offer real routes for oil operators to meet regulatory requirements, mitigating environmental impact.
A Novel Method to Boost Production from Low Production Gas Wells to Increase Overall Recovery and Avoid Well Intervention
Authors: Al-Malki Bandar H. , Baqawi Ahmed M. , Peeran Syed M , Beg N 
Published: June 2014

Abstract
Gas-condensate fields producing under natural depletion are often faced with the challenge of finding adequate, long term and cost effective solutions to energize the pressure decline in the old gas wells after long years of production and drainage depletion. The most common practice is re-entry operation utilizing a workover rig to target a new section in the reservoir or implement a new completion to conduct an advanced stimulation technique. These options are expensive and not the most effective as there will be a lengthy idle time until the workover is conducted. The problem is worsened as reservoir pressure falls below dew point which could cause liquid loading compounded by water production issues in the wellbore.
The primary objective is to boost the wellhead pressure to overcome the back pressure imposed by the downstream main gas flow system. Other than an expensive option of a workover job with a rig, a boosting system can be acquired in such cases to maintain production or to prolong the production life of the fields and increase the total rate of hydrocarbon recovery.
The innovative use of Velocity Spool (VS), commercially known as Surface Jet Pump (SJP), technology is one of the simplest and most cost effective ways to boost low pressure and revive dead wells. The SJP (or VS) system is a device that has no rotating parts which utilises pressure energy from high pressure well (or group of wells) to help low pressure well (or group of wells) flow against high pressure upstream facilities without the need for compression. Furthermore, the Velocity Spool can defer or replace the eventual use of conventional technology, such as compressors. It can also save considerable capital and operating costs associated with re-entries.
The SJP system has been successfully applied worldwide onshore/offshore to generate incremental production and optimise production process. However, the application discussed in this paper under the applied conditions is the first of its kind worldwide. This paper provides details of the recent novel SJP (VS) system applications in Saudi Aramco onshore gas fields. The implementation involved installation of the VS on ten different Low Pressure (LP) gas wells to utilize the strong stream HP well(s) that were drilled recently or producing from a more prolific reservoir section.
Recent field examples of this technology from Saudi Arabia are covered in this paper. The paper also addresses the economic aspects of the technology applications by giving an indication of the payback periods that can be achieved from the added revenue or from cost savings. Field applications have shown that the recovery of the capital spent in installing SJP (VS) systems is generally achieved within a few weeks to a few months.
Downhole Electrical Disconnect Tool Enables the Parting and Subsequent ReConnection of the Upper Completion Containing an ESP from the Lower Intelligent Completion
Authors: Izetti Ronaldo , Pinto Hardy , Rosas Fabio , Minassa Lorenzzo , Vayeda Ravi , Deyo Benjamin , Bhat Gireesh , Rodrigues Desiderio , Bonfim Antonio 
Published: June 2014

Abstract
Intelligent completions and electrical submersible pumps (ESPs) are realizing greater oilfield acceptance because of their capabilities to improve recoveries, especially in multi-zone wells where production can be controlled and optimized without intervention. Previously, when ESPs had to be removed for routine maintenance, the whole completion had to be pulled, which would require significant time, risk, and cost. Now, an electrical disconnect tool exists that enables ESPs to be changed out without requiring the lower intelligent completion to be removed. This paper discusses the equipment and methodology recently used in a trial test offshore Brazil to reliably disconnect an ESP in the upper completion from the lower intelligent completion that had two interval-control valves (ICVs) and two dual-sensor pressure/temperature gauges. The trial test required the disconnect sub to be disconnected from the receptacle, then reconnected again, followed by an ICV and gauge function test to prove the reliability of the wet mate connector in the electro-hydraulic disconnect tool.
This paper highlights the successful case history of the new disconnect tool installed in January 2013 in the Carapeba field, offshore Brazil. The paper will discuss the technical aspects of the concept, the well-planning details, completion procedures, installation lessons learned, and tool design improvements that will be adopted for use in future wells.
This installation will initiate the use of electrical disconnect tools for upcoming intelligent completions involving ESPs, sub-surface safety valves, or long horizontal sections that may require the lower completion to be installed on drill pipe.
A Graphical Method to Evaluate Multi-Reservoir Commingling
Authors: Barri Assad , Alnuaim Sami 
Published: June 2014

Abstract
Commingling technique is one of the completion design methods that have been used in many oil fields to increase oil production. This technique is used mainly when pay zones have similar rock and oil properties. Previously in vertical wells, commingling was done by opening pay zones to the well bore, but recently specially in horizontal and multi-lateral technology, commingling is achieved by drilling many lateral holes into the pay zones from the same main hole, and producing all of them at the same time. Before deciding on the commingling, some situations need to be addressed before deciding on whether it is optimum to commingle all or some of zones together or not.
In this paper, a graphical method has been proposed to assist on the commingling decision by evaluating two completion scenarios and analyze both of them graphically. This method is focused mainly on the effect of the bubble point pressure rather than the other factors because it has a major impact on the productions especially if the commingled zones have different values.
The study concluded that commingling decision becomes more likely when the commingled zones have similar saturation pressure; and vice versa. It also concluded that commingling decision becomes more likely when the zone that has the highest value of saturation pressure is deeper than the rest of the pay zones or it has a higher productivity index as compared to the rest of pay zones.
Successful Field Application of Aqueous-Based Formation Consolidation Treatment Implemented in Nile Delta, Egypt
Authors: Songire Sumit , Hassan Amro , Amer Mohamed , Farid Saber , Luijkx Jean-Marie , AbdelKhaleq Mohamed 
Published: June 2014

Abstract
Sand production can be challenging for many operators in unconsolidated formations. The production of formation sand and fines can cause erosion damage to both surface and downhole equipment, resulting in major well intervention and sand disposal costs.
Conventional resin consolidation systems have been successfully used to prevent solids production in short, homogenous intervals. However, resin consolidation attempts in longer intervals have resulted in erratic success rates, which could be attributed to a lack of complete and uniform treatment of the entire interval length. A recently developed aqueous-based resin (ABR) system has helped provide effective and efficient treatment of significantly longer intervals, has improved health, safety, security, environmental (HSSE) compatibility, and can help improve various operational considerations.
This paper discusses results of laboratory testing and the subsequent successful treatment using the ABR system within a well located in Nile Delta, which was the first attempt of its kind in Egypt.
Sieve analysis revealed unsorted formation sand, which usually requires a gravel pack completion, rather than a standalone screen; however, because of limitations with respect to wellbore diameter (5 in.), it was difficult to complete the well using conventional gravel pack completion methods.
Additionally, the well had a history of unsuccessful treatment using a non-resin product, which modifies the surface potential charges of the sand grains and reduces the repelling forces between them. The well was still producing sand after that treatment; thus, the decision was made to treat the interval using the ABR system. Thereafter, hydrocarbon production, at a rate of 5.5 MMscf/D, was monitored and sand production from the well decreased by more than 95%, with no impairment to hydrocarbon production.
Evaluate Fracturing Fluid Performance for Hydraulic Stimulation in Pre-Khuff Sandstone Reservoirs of Ghawar Gas Field
Authors: Das Prasanta , Rahim Zillur 
Published: June 2014

Abstract
The choice of stimulation fluids and proppants are very important for successful proppant fracturing. Saudi Aramco along with a few service companies had put lot of efforts on the development of the Ghawar gas field mainly in the Pre-Khuff sandstone formations in the past years. A good understanding of the fracturing fluids and its performance downhole is the key to successful stimulation of gas wells.
The design of a fracturing fluid depends on several reservoir properties such as bottomhole static temperature, reservoir fluid properties, formation permeability, rock mechanical properties etc. The pre-Khuff reservoir possesses very high temperature (in the range of 290-3400F) and high fracture gradient (0.6-0.95). Choice of particular fluid systems used during proppant fracturing is mainly governed by the bottomhole static temperature, treatment time and cost. Different types of borate-crosslinked, metal-crosslinked and viscoelastic fluid systems were used in the past with different proppant concentration. One of the major concerns with the crosslinked fracturing fluids is the damage created in the formation due to non-uniform broken fluid and unbroken gel left inside the formation after the treatment is performed. The paper provides an assessment on different fracturing fluids pumped in pre-Khuff sandstone formations and compares the performance in terms of formation damage and well deliverability from actual case histories. The paper also provides recommendations that can be implemented to assess and minimize formation damage from unbroken gel and achieve improved production.
The paper provides an overview on the different fracturing fluids, current design practices, probable damage severity due to unbroken gel and fracturing fluid performance with respect to production improvement through case studies. The study can be used as a lesson learnt for selection of right stimulation fluid and evaluation of formation damage due to fracturing fluid performance for other reservoir conditions.
A Saudi Arabia Giant Field Development: Lessons from Integrating Technologies
Authors: Arukhe James , Harthi Mabkhout , Namlah Sultan , Ahmari Abdulrahman 
Published: June 2014

Abstract
Discrete technology solutions, such as real time data acquisition, distributed temperature sensing, etc., applied on a selected-well basis, seem to serve field development engineers well sometimes. For engineers to continually improve field-wide operations and attain the cost and production advantages necessary to stay competitive in an industry shifting to cost-effective applications, integrating workflows is a strategic imperative. Engineers will need to concentrate and excel not just on specific technologies, but on holistic rigless operations success driven by more attention to integration than individual technology solutions. The challenge facing asset teams remains how to execute comprehensive plans to make significantly higher returns from capital technology spending in the field.
The scope of this paper is to present how engineers have adopted technology integration and alignment of CT reach and stimulation technology solutions for the specific situation of successfully developing and managing major oil carbonate field in readiness for a major production milestone. The approach presented entails an all-inclusive project-based method that involves performance reviews, elimination or reduction of idle times through close monitoring of incremental project stages, optimizing operational efficiency through increasing the speed of material delivery to the well sites, and improvement of logistics of people and equipment. The approach involves unifying role-based, process-based, and production workflows throughout the operation and building on a learning curve with each successive rigless operation. From the safe job execution of many rigless activities, a model or scorecard is available to control important variables, assess the effectiveness of specific technologies, and provide support for leading or lagging indicators.
Consequent upon routine and seamless inclusion of technology-based exercises at a project level, rigless activities have been completed over 60% faster than when the campaigns started nearly five years ago. Monetizing this value of technology integration in auditable and quantifiable terms translate to significant gains over the course of the rigless campaign. Through integration, engineers can implement effective programs for improvement in service levels and improve operations. Eventually these gains translate to fewer obstacles to project delivery.
Multiphase Flow Measurement Modeling of an Oil-Water Flow through an Orifice Plate
Authors: Noui-Mehidi Mohamed N. , Black Michael J. 
Published: June 2014

Abstract
Multiphase flow metering is still a challenging research area, especially when flow of immiscible liquids is considered. Actual flow models in oil and water mixtures treat, in most cases, the flow as a homogenous mixture omitting the nature of the dispersion, the slippage between phases and its implications on the measurements accuracy. Computational fluid dynamics have provided substantial improvement in capturing the flow features of multiphase mixtures. The present work is related to numerical simulations of flows through a modified orifice plate meter combined with a bluff body. The flow simulation using a mesoscopic approach has revealed the existence of a pulsation mechanism that has a characteristic frequency proportional to the flow rate.
Equilibrium Swelling and Syneresis Properties of Xanthan Gum/Cr(III) Gels
Authors: Gales J. R. , Young T. S. , Willhite G. P. , Green D. W. 
Published: June 2014

ABSTRACT
Swelling and syneresis behavior was measured by equilibrium swelling of xanthan gum-Cr(III) gels that had been aged for over 100 days. The dependence of swelling on pH, temperature and presence of calcium ion was determined. Degree of swelling varied from + 66% to -71% over the range of parameters investigated. Theoretical considerations are discussed.
Chatom Gas Condensate Cycling Project
Authors: Tompkins M. W. , Ebbs D. J. , Thomas L. K. , Dixon T. N. 
Published: June 2014

SUMMARY
A sour gas condensate reservoir simulation study using a three-dimensional black oil model with extended PVT capability for history matching and predicting residue gas cycling is presented. This rich, retrograde condensate reservoir was simulated to assist with operation and development planning including the eventual blowdown.
Paper (SPE 17353) first presented at the SPE/DOE Enhanced Oil Recovery Symposium held in Tulsa, Oklahoma, April 17-20, 1988.
Design and Application of an Alkaline-Surfactant-Polymer Recovery System for the West Kiehl Field
Authors: Clark S. R. , Pitts M. J. , Smith S. M. 
Published: June 2014

SUMMARY
The West Kiehl Unit, Crook County, Wyoming produces from the Minnelusa Lower "B" Sand reservoir. Original oil in place (OOIP) is estimated at 238, 481 m3. Estimated ultimate primary production is 27, 028 m3 or 11% OOIP. Four enhanced oil recovery methods were considered for application in this reservoir: conventional waterflood, polymer flood, an alkaline-polymer flood, and an alkaline-surfactant-polymer (ASP) flood. Estimated ultimate recoveries are 95, 392 m3 (40% OOIP), 95, 392 m3 (40% OOIP), 95, 392 m3 (40% OOIP), and 135, 934 m3 (56% OOIP), respectively. The polymer flood is expected to deplete the field faster than a conventional waterflood without an increase in ultimate recovery, while the ASP technology is expected to extend the field life and increase ultimate recovery dramatically. The ASP process has been implemented and early performance is very good.
Two purposes are being served by implementation of the West Kiehl alkaline-surfactant-polymer flood. The first is to recover additional oil not recoverable by a waterflood or a polymer flood. The second is to pilot this potentially significant enhanced oil recovery (EOR) technique for other Minnelusa reservoirs. If this method proves successful, it will represent a sizable increase in ultimate recovery with the incremental oil recovery ranging as high as 25% OOIP.
This paper discusses the goal for utilizing the alkaline-surfactant-polymer technology at the West Kiehl. Further, it details the development of the West Kiehl Field project including laboratory studies, reservoir parameters, initial injection and production history, facilities design, and operations of the flood.
A New Approach for Simulation of Cyclic Steam Stimulation Above Fracture Pressure by Modifying a Thermal Simulator
Authors: Lin C. Y. 
Published: June 2014

SUMMARY
A fracture propagation model that includes fracture propagation kinematics and heat transfer between the fracture and the reservoir was developed by modifying an existing thermal simulator. The induced fracture was assumed to be highly conductive, and fracture storage was neglected. The model was applied to simulate cyclic steam stimulation processes for a typical heavy oil reservoir. In single-well simulation, a lag time between the beginning of the injection and the initiation of the fracture is predicted. This lag time increases with the cycle number while the maximum fracture length decreases with the cycle number. The fracture characteristics in multi-well pattern simulation are drastically different from the single-well case because of well interactions.
Viscous Fingering in Heterogeneous Porous Media
Authors: Araktingi U. G. , Orr F. M. 
Published: June 2014

SUMMARY
Formulation of a particle-tracking model for calculation of unstable flow in heterogeneous porous media is described. Model calculations are compared with unstable laboratory-scale displacement experiments, and excellent agreement is demonstrated.
Simulations of unstable displacements in heterogeneous porous media are also described. They indicate that if variations in permeability are uncorrelated, or if the variance of the permeability field is small, then finger patterns are similar to those observed for homogeneous porous media. When the permeability is sufficiently variable and the correlation length is a significant fraction of the flow length, however, the permeability distribution dominates the formation of ringers, and the fingers follow the same path regardless of the mobility ratio. A heterogeneity index, defined as the product of variance and dimensionless correlation length, is used to characterize the transition from flow dominated by viscous fingering to flow dominated by the spatial distribution of permeability.
Precession of Rotary Drillstrings Should be Eliminated
Authors: Zhang Y. L. , Xiao Z. Y. , Duanmu G. 
Published: June 2014

SUMMARY
Results obtained using a scale model of several hundred metres of a drill string are presented. The model has shown that the rotary drilling process is dominated by precession of the drill string. The nature of this motion is explained, along with its relationships to bending stress and torque. It is suggested that high speed precession contributes significantly to bending fatigue of drill strings; and eliminating the precession is the approach to prolong the service lives of rotary drill string components and to carry out high speed safe drilling.