bluuebunny/crossref_metadata_2025_split huggingface dataset:
Rheological Study for Surfactant-Polymer and Novel Alkali-Surfactant-Polymer Solutions
Authors: Bataweel M. A. , Nasr-El-Din H. A. 
Published: February 2012

Summary
Mobility control during chemical flooding is one of the most important factors for enhanced oil recovery using chemical processes. Polymers are used to increase the viscosity of the injected fluid and improve the sweep efficiency by having a favorable mobility ratio during chemical flooding. Characterization of rheological properties of the surfactant-polymer (SP) and alkali-surfactant-polymer solutions is important for understanding the behavior of chemical slug in porous media.
An experimental study was conducted to measure the rheological properties of chemical flooding solution over a wide range of parameters. Effects of temperature, salt type, salt concentration, surfactant type and surfactant concentration on dilute aqueous solution of polymer used for high salinity enhanced oil recovery applications were investigated in details. In some cases the chemical slug was prepared in seawater and viscosity measurement was conducted at 90°C.
Amphoteric surfactant was used and showed compatibility with polymer solution and can be used in chemical flooding. Effect of concentrations of two types of surfactants, anionic and amphotaric on chemical slug viscosity was studied. Amphotaric surfactant was found to have a preferable rheological attributes when compared to anionic surfactant. Amphoteric surfactant can maintain viscosity of chemical solution at high salinity and no reduction in viscosity was noticed when this type of surfactant was added to the solution. On the other hand, reduction in viscosity was measured when anionic surfactant was added to the solution. Dynamic properties showed reduction when salts were added to the solutions.
Performance Assessment and Optimization of Liquid Petroleum Gas Demercaptanization Process (A Case Study)
Authors: Davoudi M.. , Khoramdel I.. , Bazregari B.. 
Published: February 2012

Abstract
Propane and butane as LPG product containing undesirable sulfur compound which are causing a nasty smell of the product and bad copper plate corrosion. Decreasing of sulfur content tend to sale cost increasing. Total sulfur content of liquefied Petroleum product from a gas refineries located in south pars (south of Iran) presents fluctuation and off specification product occasionally. In this paper we intend to investigate and analyze the results obtained and describe the effects of important parameters on critical point of de-mercaptanization process. Also some modification is presented, based on data field, to decline the total sulfur of product and performance enhancement of process.
Downhole Pressure Uncertainties Related to Deep Wells Drilling are Safely and Precisely Ascertained using Automated MPD Technology
Authors: Vieira P.. , Torres F.. , Qamar R. A. , Marin G. E. 
Published: February 2012

Abstract
Drilling Deep Wells leads to face harsh operational conditions such as HP/HT, wellbore stability issues, narrow influx/losses windows which consequently make these prospects costly inefficient and highly risky safety wise, especially if the case is an exploratory well. Managed Pressure Drilling (MPD) is an enhancement of the primary well control provided by the utilization of a closed and pressurizable circulating system for the drilling fluids (mud), this enables drilling with precise management of the wellbore pressure profile, aiming to optimize drilling processes by decreasing nonproductive time (NPT), mitigating drilling hazards and to enable the drilling of otherwise technically or economically un-drillable and high-complexity prospects, offering a considerable amount of tangible benefits. Because MPD addresses NPT, the technology is of greatest potential benefit to deep wells drilling programs where cost of dealing with troublesome zones while drilling is much higher.
Several wells ranking from appraisal to wildcat exploratory with considerable pore pressure unknowns, coupled with narrow pore-fracture drilling window characteristic of HPHT conditions have been already drilled under the MPD technology in the MENA region. MPD was able to minimize the problems faced on previous wells conventionally drilled, by enabling various techniques which include the use of pressure build up analysis to quantify formation pressures, the application of dynamic flow checks, dynamic formation strength limits, and the application of constant bottom hole pressure during dynamic (pumps-on) and static (pumps-off) drilling fluid conditions. There are different providers at diverse levels of complexity that approach MPD systems. The system mostly selected by the operators to drill deep wells consists of an automated surface choke control system based on the mass balance monitoring principle and Rotating Control Device (RCD). The advantages of an automated MPD system are related to a quick reaction to the expected drilling problems and formations pressures uncertainties, all linked with the drilling process of an exploratory deep well. Drilling-related issues such as excessive mud cost, slow rate of penetration (ROP), wellbore ballooning/breathing, kick-detection limitations, difficulty in avoiding gross overbalance conditions, differentially stuck pipe, twist-offs, and resulting well-control issues contribute to the decision of applying the MPD technology. This presentation summarizes the application of MPD to address drilling hazards by drilling with more precise wellbore pressure management utilizing an automated MPD system based on flow balance monitoring, adding value to the conventional drilling practice.
Drilling Hazard Mitigation Technology Enables Conventionally Undrillable Prospects To be Drilled With Reduced Nonproductive Time and Increased Operational Safety: Application of Solid Expandable Liners and Managed Pressure Drilling in Algeria Nezla Field
Authors: Hamoudi I.. , Kartobi K.. , Vieira P.. , Saad M. A. , Torres F.. , Qutob H.. 
Published: February 2012

Abstract
The Nezla Field is a faulted anticline that makes conventional drilling challenging due to the presence of fractured and high pressure formations in the Triassic and Ordovician groups, representing trouble zones that jeopardize well objectives, adding costs and operational risks to the drilling process. This adverse condition was observed in the offset wells drilled with problems related to wellbore instability, lost-circulation zones and over-pressured formations leading to kick/loss well control scenarios that endangered the drilling operations and incurred significant Non-Productive Time (NPT). A Drilling Hazard Mitigation (DHM) approach was implemented to offset the risks of both deviating from the well objective and drilling plan.
The constraint to drill the planned 12-1/4" section in the well was the unpredictability of the pore/fracture pressure in the transition zone between Tags and Sandy Tags formations, representing a high level operational risk. The most optimum and reliable solution to achieve the goal of drilling this zone without loss of hole size was to set 9-5/8" casing shallower than planned and then isolate the lower section of Tags formation (abnormally pressurized) with an Open Hole Expandable Liner. Drilling the next hole section through the low pressure formations to set the 7" casing shoe was to be resumed as per the original plan. This allowed the 6" reservoir hole section to be drilled under the Managed Pressure Drilling (MPD) mode.
The CBHP (MPD technique) was planned to drill the 6" section through the tectonically fractured Sandstone Hamra Quartzite maintaining the ECD within the drilling window limits initially defined by the predicted formation pressure and the average mud hydrostatic with which fluid losses were experienced in the offset wells. While drilling, these limits were ascertained within the range of 1.26 SG EMW – gas influx and 1.32 SG EMW – fluid losses. The CBHP drilling mode enabled to manage the ECD in between influxes and losses only adjusting the well head pressure to obtain instantaneous changes in the Bottom Hole Pressure while circulation was in progress. During the pumps-off periods, back pressure was applied on the MPD choke by pumping mud across the top of the well to compensate the Annular Friction Loss pressure. Once these limits were reached, drilling progressed with managing simultaneously small gas influxes and tolerable losses; then TD was called since the risk of simultaneous total losses and gas Influxes in the underlying Hamra fault was increasing.
This paper describes in detail the DHM technology implemented in this well and presents the successful application of such technique to enhance Nezla field exploitation. Lessons learnt and challenges encountered will be also discussed.
Modelling of Hydraulic Fracturing in a Weak Permeable Formation
Authors: Sarris E.. , Papanastasiou P.. 
Published: February 2012

Abstract
We present numerical results of a propagating hydraulic fracture in weak rock formations. The results were obtained from a Finite Element Hydraulic Fracturing model which simulates all the involved non-linear and coupled processes. The fracture is driven by pumping of an incompressible viscous fluid with Newtonian rheology. The fracturing fluid leak-off in the host rock formation is also considered. For propagation criterion a cohesive-softening model is implemented in interface finite elements and the bulk rock deformation is modelled by Mohr-Coulomb yield criterion. The main objective of this research work is to determine the influence of the stress-field, pore pressure field and pumping parameters on rock plastic deformation and its implications on fracturing net-pressure and fracture dimensions. It has been previously shown that in weak formations plastic yielding and the associated rock dilation create shielding of the fracture tip and hence larger pressures are needed to propagate the fractures and the created fractures are shorter and wider. We extend these studies to investigate the influence of the pore pressure which has been previously ignored. We found that high anisotropic stress field and high initial pore-pressure fields increase the plastic yielding in a rock formation demanding higher net-pressures for propagating a fracture and the created fractures are shorter and wider. This non-linear analysis and results may explain the differences observed in net-pressures between field measurements and conventional model predictions. These findings are important in improving the numerical simulators of modelling hydraulic fracturing in particular for short fractures in weak formations for sand control applications. The results are also important to better prediction of vertical fracture growth and containment in shale-natural gas stimulations where there are serious environmental concerns on the risk of ground-water contamination.
Utilize Real-time MWD Data for Wellsite Job Optimization to Provide a New Level of Process Control in Well Intervention
Authors: Mohamed Omar 
Published: February 2012

Abstract
A new application for downhole data acquisition provides real-time wellbore intervention optimization via measurement-while-drilling (MWD)-based technologies to enhance pipe-conveyed wellbore intervention operations. This paper discusses the incremental challenges of conventional fishing methods that are addressed by using downhole data acquisition technology for ‘smart intervention’ service in the following:
Casing exits
Casing milling
Packer milling
Retrieving deepset plugs
Pulling gravel-pack packers
Wellbore cleanup
A smart intervention module is one solution that is run in the workover string as close to the wellbore intervention bottomhole assembly as possible. It provides its own power supply, telemetry system, and sensors, and data is sent from the module via mud pulse telemetry to the surface, where it is displayed clearly on a rig floor monitor.
Surface rig-up requires a pressure transducer on the stand pipe or pumps, cables from the transducer to a junction box and the processor, which is connected to two real-time laptops. The smart intervention engineers provide 24-hr coverage, and both the smart intervention module and the surface equipment are included in the services provided.
The smart intervention system gathers downhole measurements like weight on tool, torque, revolutions per minute, bending moment, vibrations, pressure, and temperature to provide a clearer picture of what is occurring at and around the wellbore intervention tools. The data is then transmitted to surface where accurate, real-time decisions and adjustments can be made to optimize downhole intervention operations.
Hydraulic Fracturing as Development Strategy in the Congo Onshore
Authors: Perfetto R.. , Martocchia F.. , Binda A.. , Itoua R.. , Tita G.. , Ceccarelli R. L. , Tealdi L.. , Cafarelli R.. 
Published: February 2012

Abstract
The benefits of Hydraulic Fracturing (HF) are well recognized in the oil industry, even if in many world regions it is still seen as a remedial operation rather than a reservoir development strategy. The big part of worldwide HF operations, are performed extensively in the US and Canada, primarily for reservoir development purposes of tight gas fields. However during the last few years, the global trend has seen a change and HF is now encouraged for adding new reserves, aiding the development of low permeability marginal reservoirs and prolonging life of brown fields.
In Congo Onshore, HF is now a consolidated reality, with more than 70 frac jobs pumped. Good results have encouraged management to increase fracturing activity: nowadays HF is performed on all the infill wells that are drilled in the low permeability layers of the reservoir.
From the early stages of development only the layers with the higher permeability were produced, while the possibility to develop the low permeability layers was not considered, because of very poor or zero production results due to the application of conventional completion strategy.
Since HF is now performed as a standard practice on new wells, it has been reconsidered for the application on old wells completed in the low permeability layers.
The challenge encountered on these old wells, has been the presence of long perforated interval.
Rigless operations (such as sand plug) and work-over operations (such as cementing of old perforated interval and re-perforations) have been needed for fracturing in order to avoid fracture initiation issues like multiple fractures and early screenout.
This paper will show the lessons learned and the main results achieved during this campaign and it is particularly focused on operational and logistic aspects, offering a full operational overview to all Companies and Operators that intend to apply this technology on their assets, maximizing oil recovery.
Selection of Technology for Produced Water Treatment
Authors: Das Pares Chandra 
Published: February 2012

Abstract
Selected technology for Makeup (MU) and Produced Water (PW) Treatment of thermal facilities (Cyclic Steam Stimulation (CSS), Steam Flood (SF) and Steam Assisted Gravity Drain (SAGD) plays an important role in the CAPEX and OPEX of the plant. This paper summarizes merits and demerits of the available technologies for PW treatment and presents a case study to establish the best solution for the ongoing design of the commercial plant of Kuwait Oil Company (KOC) for its initial phase of operation. To meet the production target, the time for collecting design data for PW from the pilot is not available to select the proper technology for PW treatment. Due to lack of proper analysis of PW, a conservative approach was made to select the PW treatment technology by using the analysis of the formation water with high Total Dissolved Solid (TDS). For the high TDS the selected technology was Mechanical Vapour Compression (MVC) system, a unit with high CAPEX and OPEX and is totally a new technology for CSS and SF process. With the case study, the paper demonstrates that although the formation water is with high TDS but the amount of coupled PW per barrel of crude could be very low. Thus with CSS and SF process, the TDS content of the produced water could be reduced substantially and MVC may not be an option. Field data showed as the sufficient amount of MU water is available, the need for recycling PW can be deferred. The technology for PW treatment will be selected based on the initial operating data. The accepted proposal will help the project to select the appropriate technology based on proper data of the commercial plant and may lead to a practical and economic design.
Artificial Lift of Water in Gas Wells
Authors: Bugbee William Charles 
Published: February 2012

Abstract
Optimizing well production is the key to increasing profits. That's why a growing number of natural gas producers are using innovative technology to capture more gas and increase well life. Traditionally, several separate devices have been used to perform measurement and control tasks. Now, a single flow computer streamlines operations by measuring gas and, by providing pipeline and wellhead control. This paper will show the benefits of using a top of the line flow computer with well tested a proven algorithm to increase production and life of a well.
The principle of the plunger is basically the use of a free piston acting as a mechanical interface between the formation gas and the produced liquids, greatly increasing the well's lifting efficiency.
The successful operation of these systems is predicated on the assumption that the wells have no packer or have communication between the tubing and the casing at the bottom of the production string.
An Integrated Model for History Matching and Predicting Reservoir Performance of Gas Condensate Wells
Authors: Farid A. M. , El-Banbi A. H. , Abdelwaly A. A. 
Published: February 2012

Abstract
Depletion performance of gas condensate reservoirs is highly influenced by changes in fluid composition below the dew point. Long-term prediction of condensate gas reservoir behavior is therefore difficult due to the complexity of both composition variation and two-phase flow effects. In this paper, an integrated model was developed to simulate gas-condensate reservoir behavior. The model couples the compositional material balance or the generalized material balance equations for reservoir behavior, the two-phase pseudo integral pressure for near wellbore behavior, and outflow correlations for wellbore behavior.
An optimization algorithm was also used with the integrated model so it can be utilized in history matching mode to estimate original gas in-place, original oil in-place and productivity index parameters for gas condensate reservoirs. The model can be used to predict the production performance for variable tubing-head pressure and variable production rate. The model runs fast and requires minimum input.
The developed model was validated using different simulation cases generated with a commercial reservoir simulator for variant reservoir and well conditions. The results show a good agreement between the simulation cases and the integrated model. After validating the integrated model against the simulated cases, the model was used to analyze production data for a rich gas condensate field (initial CGR of 180 bbl/MMscf). Tubing head pressure data for four wells was used along with basic reservoir and production data to obtain original fluids in place and productivity indexes of the wells. The estimated parameters were then used to forecast the gas and condensate production above and below the dew point. The model is also capable to predict reservoir pressure and bottom-hole flowing and tubing head pressures and can account for completion changes when they occur.
Guidelines to Optimize CO2 EOR in Heterogeneous Reservoirs
Authors: Shehata Ahmed M. , El-Banbi Ahmed H. , Sayyouh M. Helmy 
Published: February 2012

Abstract
CO2 flooding in oil reservoirs to enhance oil recovery is successfully applied in many ongoing projects in the world. The bulk of industry research and field testing of CO2 has been directed towards miscible displacement. This method of using CO2 appears to have the greatest potential for recovery of oil that would not have been recovered using conventional production methods.
The main objectives of this paper are to investigate the most important reservoir and operational parameters in CO2 flooding and to provide guidelines to maximize CO2 injection performance for different levels of reservoir heterogeneity. Several compositional simulation models were generated using actual field data. For each model, reservoir heterogeneity was evaluated using Lorenz and Dykstra Parsons coefficients. The different compositional simulation models were setup to investigate the effects of key parameters such as injection rates, injection patterns, well spacing, injection scheme (Continuous CO2, WAG, and SWAG), WAG cycle length, vertical to horizontal permeability, and horizontal injection wells on the recovery factor and production of CO2 projects.
Those different heterogeneous models were used to simulate different scenarios over a wide range of both reservoir and operational parameters and provided a comprehensive data set to evaluate the CO2 flood effectiveness in a variety of conditions. More than 700 simulation runs were designed using Experimental Design techniques to test those parameters. Several correlations (proxy models) were also developed and blind tested to check their effectiveness in predicting the performance of combination of parameters that were not even tested. As a result of this work, it is possible to use experimental design to test the performance of CO2 injection. It can be performed with acceptable accuracy by performing a limited number of runs; hence, reducing the time, effort, and money.
It was observed that the use of different heterogeneous models resulted in different overall field performance. Our results also showed that implementing WAG and horizontal wells enhance the oil recovery significantly.
Increasing Propane Productivity by Changing the Operating Conditions without Adding any New Facilities
Authors: Riad Tamer Hamdy 
Published: February 2012

Abstract
Gasco operates two NGL plants located in Alexandria; Amerya LPG plant and Western Desert Gas Complex (WDGC). Recently, Gasco has started up a new project that integrates the two plants to maximize Ethane and Propane productivity.
The project design is based on adding new process facilities in Amerya plant to start producing C2+ that directed to WDGC, while a new train is added in WDGC to increase the feed gas capacity and maximize C2+ recovery by applying the Gas Subcooled Process (GSP) as Ethan mode of operation scheme.
This paper presents a study to increase the productivity of the two plants by using simulation software to help the decision making for what the optimum conditions should be applied in different modes of operation to increase the production.