bluuebunny/crossref_metadata_2025_split huggingface dataset:
Inflow Control Device an Innovative Completion Solution from "Extended Wellbore to Extended Well Life Cycle"
Authors: Al Arfi Saif Ali , El Abd Salem Salem , Keshka Ashraf Al-Saiid , Al-Bakr Salem , Amiri Abdel Hameed , El-Barbary Abdalla Youssef , Elasmar Magdi , Mohamed Omar Y. 
Published: March 2009

Abstract
This paper will describe a new production technology system that enabled focusing on achieving performance objectives in addition to finding and fixing production problems.
Inflow Control Device (ICD) is a new completion system that will optimize production, delay water progress, eliminate / minimize annular flow, and ensure a uniform inflow along the horizontal wellbore at the cost of a minute pressure drop. The non-uniform production profile across the horizontal hole especially in the highly heterogeneous and fractured reservoirs can result in premature water production, bypassed oil and lower ultimate recovery. The problem was identified through production logging of several horizontal wells, which indicated a non-uniform production profile across the horizontal holes.
The successful implementation of this technology was achieved by the use of an integrated approach to select the appropriate technology and method for addressing the problem. A business case was developed at which all key factors comprised a successful completion strategy in both drilling of a new well and work-over of an existing well. Among these key factors the development of multidisciplinary team; matching a good intervention candidate well with the appropriate technology; properly designing the well segmentation and execution of the design with rigorous quality control.
A case history will be presented where this new production technology, has resulted in significant Net Present Value (NPV), and improved production via an extended well-life cycle. The ICD Equalizer system was installed in one new and an existing well with the aim to evaluate the viability of the technique.
Both installations were successful and the preliminary surface testing results of the wells performance on different rates indicated a niform production profile across the horizontal hole and a drop in the existing well water cut (from 7% to traces). Although the new well has penetrated fractures as expected, the well did not show water production since installation (Febrauary 2007) till the time of writing this paper.
With field-scale implementation, the economic analysis revealed an improved NPV and an incremental recovery factor increase about 1%.
Effect of Brine Salinity on Interfacial Tension in Arab-D Carbonate Reservoir, Saudi Arabia
Authors: Okasha Taha M. , Al-Shiwaish Abdul-Jalil A. 
Published: March 2009

Abstract
Carbonate reservoirs contain more than 50% of the worlds's hydrocarbons reserves. In Saudi Arabia, most of the current hydrocarbon production is from Arab-D carbonate reservoir (Upper Jurassic limestone). Oil production started 50 years ago. So, the various fields had been subjected to prolonged pressure support by waterfloods (since 1970) using high salinity brine (Arabian Gulf water). Oil recovery using waterflooding is about a third of the oil original in place (OOIP); while two-thirds still remain as a target for additional recovery.
Low salinity waterflooding was introduced as an enhanced oil recovery technique from at least 65 years. Interfacial tension (IFT) between oil and brine during waterflooding has a significant effect on oil recovery and production strategy. So, this study was carried out to investigate the effect of brine dilution, temperature, and pressure on IFT of dead and recombined oil in Arab-D carbonate reservoir as the first phase in evaluating the potential of low salinity flooding technique to improve oil recovery.
In this study, Arab-D reservoir brine with total dissolved solids (TDS) of 214,943 ppm was mixed with distilled water in two proportions resulting in a first solution with TDS = 107,906 ppm and a second with TDS = 52,346 ppm. For reservoir brine and each diluted brine, crude oil/water IFT was measured at reservoir conditions. Test results showed a decrease in IFT values for both dead and recombined oil as the volume percent of brine in the mixture decreased. IFT decreased with increasing temperature at constant pressure and increased with pressure at constant temperature. Such results show that low salinity flooding may be a good technique to improve oil recovery in Arab-D carbonate reservoir. This will require an intensive experimental coreflooding tests due to complexity of the Arab-D reservoir.
The Application of Streamline Reservoir Simulation Calculations to the Management of Oilfield Scale
Authors: Fawzy Tharwat , Mackay Eric 
Published: March 2009

Abstract
Inorganic scales precipitate in oilfield systems - downhole in the reservoir, in the production flow tubing, and in surface facilities - because of thermodynamic changes that affect the flowing brines. These changes may be induced by temperature or pressure changes, or by mixing of incompatible brines. While much work has been performed to study the effect of thermodynamic changes such as pressure decrease or temperature increase on scale precipitation, it is only recently that a body of work has been developed on the impact that the dynamics of brine mixing in the reservoir has on scale precipitation in situ. Much of this work has been conducted using finite difference simulators, which are handicapped with regard to these calculations in that numerical dispersion effects can be orders of magnitude greater than physical dispersion.
The introduction of chemical reaction calculations into streamline simulation models presents a very significant opportunity for improving the accuracy of such calculations. While numerical dispersion effects for immiscible calculations (eg water displacing oil) can be countered by pseudoisation of the relative permeability functions, in finite difference models it is difficult to control numerical dispersion for miscible displacements - eg seawater (with a Sulphate concentration) displacing formation water (with a barium or strontium concentration), which may lead to scaling in the reservoir (BaSO4 or SrSO4 precipitation). Streamline simulation reduces the numerical errors for both miscible and immiscible displacement - so making the scaling calculations much more accurate.
The objective of this paper is to study the application of a streamline simulator that has the appropriate chemistry modelling capabilities to realistic reservoir scenarios. The calculations performed demonstrate where, and under what conditions, scale precipitation takes place in situ in the reservoir, and what the resulting impact on the chemical composition of the produced brine will be. This information is key in the planning of management of oilfield scale, especially in developments where options for scale mitigation may be limited.
Holistic Approach for Regional Depletion Plan Supporting Gas Supply in the Nile Delta of Egypt
Authors: Hussien Mohamed Samy M. 
Published: March 2009

Abstract
This paper shows practical example in the direction of building "holistic regional depletion plan" by applying "fully holistic" and "fully probabilistic" modeling at the cost of the classic "precision" modeling that tends to include more physics. The approach came as a result of the oil industry low return on investment (ROI) that averaged at 7%. Deterministic methods usually ignore the full uncertainties distribution, associated risks, the diversification effects, and the interdependencies among the chosen assets. In addition it loses the proper interaction between the technical and the commercial value drivers. As a result, many rated oil companies fall since 1990 until near future.
To achieve more realistic results, decision and risk analysis (D&RA) approach together with a "holistic strategy" (based on the Nobel-Prize wining portfolio theory that has shaped the financial markets over the past four decades and recently introduced to E&P) are applied instead of the conventional deterministic method and the "hole-istic strategy" that may lead to suboptimal solutions. Assets in the Nile Delta of Egypt were chosen to apply more modern modeling techniques by using less model "precision" for more comprehensive modeling of uncertainties and more integrated technical and business modeling. Full probabilistic methods that closely integrate technical and commercial data and tie that to the decision-making process are used to preserve more relevant information. This allowed the pertinent uncertainties to be exploited better and risks to be quantified when compared to the traditional deterministic methods. Optimization was carried out within the whole "value chain" at different "hierarchical levels" instead of optimizing parts separately that may destroy the whole value chain.
With the current volatile oil market and the 2008 international financial crisis, integrating the endogenous factors (local uncertainties such as geology) and the exogenous factors (global uncertainties such as geo-economics) reduces the risk of the volatile oil prices and the political events. Proper risk evaluation and quantification for many assets enables to build reasonable efficient frontier (EF) that a firm can use to decide its optimum situation depending on the firm willing and to avoid misallocation of capitals.
Integrating Real-time Downhole Data to Enhance Gas-lift Completion Strategies and Perforation Practices
Authors: Ibrahim Hanaey D. , Al-Balushi Sameer , Al-Shizawi Wafa , Beattie Stephen 
Published: March 2009

Abstract
This paper discusses the use of downhole gauges not only for monitoring pressure and temperature, but also production-optimization, enhancing completion design, perforating activates and cost-management efforts.
Real-time downhole gauges have been used in oil fields for many applications in the past. Despite this, permanent downhole gauges have only been installed for gas-lift wells in one of PDO's fields since 2007. The requirement for the monitoring system was to closely monitor the bottomhole conditions for the purpose of water injection in a 5-spot pattern application.
Openhole logs and individual reservoir pressure data of a well in 2007 indicated a variation in reservoir pressure values across the encountered zones. The decision to install permanent gauges offered the possibility to perforate the wells selectively in stages and measure the extent of underbalance prior to and during perforation operations. A technical and commercial comparison among perforation operations methods revealed that such an approach could result in better production performance and cost management. Data from the gauges provided ideas for improving perforation practices, such as spotting light oil against the perforated interval to minimize reservoir impairment.
Installing permanent gauges in 2008 clarified three important areas: the wireline operations prior too perforation; the correct method for perforating; and the adherence to the issued program.
While kicking off the well using gas lift, readings from the gauges revealed a gas-lift valve problem that instantly led to the decision to suspend perforation and change the malfunctioning valves. After rectifying the issue, perforating operations resumed and individual production tests were carried out to clarify the well's further potential. As a result, an operating-expense saving of more than $500,000 was achieved in the 2008 new well campaign. The added benefit of improved completion operations and production optimization has proved very useful.
Validation of Fracture Lineaments With Dynamic Well Data, Improves History Matching of a Dual Porosity-Permeability Model
Authors: Mubarak Saeed M. , Ali Zaki A. , Pham Tony R. , Le Maux T. , Colomar F. M. 
Published: March 2009

Abstract
Simulating fractured carbonate oil reservoirs using the conventional single-porosity/single-permeability (SPSP) model does not normally capture the whole fluid flow mechanism in the system. A dual-porosity/dual-permeability model (DPDP) conditioned by field dynamic data can lead to better fluid saturation matches.
This paper presents a new approach to history matching of naturally fractured reservoirs using a DPDP model that incorporates integrating production field performance data into the geological fracture model. A case example from a carbonate reservoir model will be used to illustrate this approach.
The construction of the fracture model was done by emplying structural lineaments from 3D seismic data, and then enhanced by integrating engineering data into the model. The engineering data included mud losses during drilling, flowmeter surveys, transient well test analysis and water production data.
The upscaled 3D fracture model was then used for history matching. With only minor modifications to the fracture model, a simulation model yielded a reliable match for water production. Furthermore, eighty percent of mud loss occurrences were in agreement with the 3D seismic lineaments mapping.
A New Stick-Slip Prevention System
Authors: Kyllingstad Åge , Nessjøen Pål Jacob 
Published: March 2009

Abstract
Stick-slip is a dysfunction of rotary drilling, characterized by large cyclic variations of the drive torque and the rotational bit speed. It is recognized as a major source of problems, such as excessive bit wear, premature tool failures and poor drilling rate.
This paper presents a new system for curing and preventing stick-slip motion. Like other competitive systems it fights the stick-slip oscillations by smart control of the drive. But in contrast to other active systems it does not use any kind of torque feed-back, not even the motor current. Fundamentally, the system is a PI-type speed controller that is tuned to effectively dampen torsional vibrations at the observed stick-slip frequency. In addition to automatic tuning of the speed controller the system includes a suite of support functions, such as automatic determination of the stick-slip frequency, estimation of the instantaneous bit rotation speed and calculation of the stick-slip severity, defined as the normalized downhole speed amplitude. All software is implemented in a standard programmable logic controller (PLC).
The paper also includes results from a field test and from Hardware-In-the-Loop (HIL) simulation tests. In the latter tests utilizing the HIL, the software runs on a PLC communicating with an advanced real-time computer model for the drive and the drill string. HIL testing has proved to be cost efficient because the PLC software can easily be tested over a wide range of different downhole conditions that rarely occur in the field.
The Application of Surfactin Biosurfactant as Surfactant Coupler in ASP Flooding in Daqing Oil Field
Authors: Wang D. , Zhang Y. , Yongjian L. , Hao C. , Guo M. 
Published: March 2009

Abstract
After conventional water flooding processes the residual oil in the reservoir remains is likely to be around 70% of OOIP. The EOR method socalled alkaline-surfactant-polymer (ASP) flooding has proved to be effective in laboratory experiments and field projects .At present restricts to application of this technique is surfactant development. biosurfactants has characteristic of low poisonous, no pollution, inexpensive. Therefore biosurfactants could be used as an economical alternative to chemical surfactants in ASP flooding is feasible. This paper studied the feasibility of using biosurfactant-Surfactin-fermentation liquor (SF) as a complementary agent of alkaline-surfactant-polymer (ASP)-flooding was conducted in the laboratory. The results show that The activity of Surfactin is tolerance to high salinity(0~12 wt%), high temperature(50-100 °C), wide pH range(6.0~11.0) and high Ca2+/Mg2+ concentration. And this surfactin could reduce IFT of water/oil from 23.53 mN/m to 4.57 mN/m , Its critical micelle concentration was tested to be 33.3 mg/L, and it had excellent emulsifying(2.89U) and foaming property. The interfacial tensions (IFTs) between solutions containing SF or mixture of SF and alkylbenzene sulfonate (ORS) at different ratios and crude oil were studied at a constant NaOH concentration. The results show interfacial characteristics (IFT) of SF and significant synergic effect between SF and ORS. The core-flooding tests show that the enhanced oil recovery with the formulation of ASP of 0.1 wt.% SF and 0.1 wt.% ORS is 7% more than that with the formulation of ASP of only 0.1 wt.% ORS, and is equal to that with the formulation of ASP of 0.3 wt.% ORS. This indicates that using SF can reduce the cost of ASP flooding.
Towards the e-field: Continuous Monitoring of Pore Fluid Phase using Horizontal Wells
Authors: Evans B. J. , Hartley B. , Keshavarz N. 
Published: March 2009

Abstract
The electric or e-field has been discussed at length in literature, in terms of the methodology of continuously remotely monitoring oil field production over a long term using vertical and horizontal wells, and transmitting data back to a monitoring centre. Conventional vertical well monitoring methods is adequate to monitor at points around an oil field but continuously monitoring where fluids are moving requires monitoring over an area using horizontal wells.
Recent research has shown that seismic methods can show subtle changes in pore fluid phase which enhances the potential for long term monitoring where pore pressure is reducing, where injected water or CO2 flood options have been chosen, and areas where gas is being replaced by water. If we can marry the use of slim-hole horizontal sensor cables with this recent demonstration of the detection of phase changes, then we have the tools for the first applied e-field scenario.
During 2007, laboratory tests injecting different amounts of CO2 into pore water showed that by monitoring the seismic transmission through a simulated rock, there was a change in seismic frequency response and transmission amplitude. Physical modeling has shown that a horizontal slim-hole well drilled to test the ability to put sensors in a horizontal well, can then be used for remote reservoir surveillance. A seismic source which walks around at the surface, produces data which is then processed to produce an indication that this method can be used as a first step for determining pore fluid properties over an area.
This paper presents the results of the experiments on pore fluid phase and discusses how the use of horizontal wells allows the ability to develop the e-field concept towards reality.
Development of Water Saturation Sensitivity Charts for Different Shaly Sand Models for Uncertainty Quantification of Volumetric In-Place Estimate
Authors: El-Sayed Samiha S. 
Published: March 2009

Abstract
Quantifying the uncertainty in the volumetric estimation of original oil in place (OOIP) is an important process in evaluating the field potential and hence in designing the proper and the most economical subsurface and surface facilities to produce the field reserves. This uncertainty in the OOIP estimate results from uncertainty in reservoir areal extent, net reservoir thickness, porosity, and hydrocarbon saturation. In this work, a methodology is presented to assess the uncertainty in the hydrocarbon saturation estimated from open hole logs using the commonly used empirical and theoretical shaly sand models.
This technique is based on development of water saturation sensitivity charts for the most commonly used water saturation models (Simandoux, Indonesian, Waxman & Smits, Dual Water, and Effective Medium) due to the uncertainty in the different input parameters to each model separately. Both analytical and numerical error analysis techniques were used to develop these charts and hence used as a forward tool to quantify the uncertainty in the hydrocarbon saturation due to the uncertainty in the core and shale properties.
Fifteen wells with 1300 shaly sand points from Alam Bewab formation, in Western desert of Egypt, were used as the data base in generating these sensitivity charts. The uncertainty in input data was assumed from ± 5 to ± 15%. The results showed a significant range of uncertainty in hydrocarbon saturation estimate from ± 2% reaching to ± 75% in some models.
General water saturation sensitivity charts were developed, for each model, based on the above mentioned database and validated mathematically. These charts can be easily used to predict the uncertainty in hydrocarbon saturation estimate due to uncertainty in the input data. In addition, it can be considered as a useful screening tool to select the best saturation model to be used depending on the input data uncertainty.
A Study of Temperature Dependent Friction in Wellbore Fluids
Authors: Kaarstad E. , Aadnoy B. S. , Fjelde T. 
Published: March 2009

Abstract
Increased well reach is one of the most important developments in modern drilling. Wellbore friction plays a central role here, both related to the drilling and to the completion phases of a well. The oil industry, however, uses the simple one-parameter Coulomb friction model to analyze well friction, without temperature effects.
The University of Stavanger has conducted friction research over some years, trying to further understand mechanical, viscous, temperature and material frictional effects. This paper presents some results of this work. Many water and oil based drilling muds from several mud vendors have been measured. The test equipment used includes a heat element to study the temperature effect on friction. The data reported cover a temperature range of 10°– 100°C.
As expected, oil based fluids have lower friction coefficient than water based fluids. The coefficient of friction increases with temperature for all fluids, except for one mud which showed nearly constant friction above 50 °C. There is considerable variation between the different fluids. Friction coefficients have been measured with steel on steel, steel on concrete and steel on rocks. Steel on rock exhibit higher friction due to higher surface roughness of the rock material. An equation for temperature dependent coefficient of friction is derived, and it is used in the field example. It is shown that the temperature effect on friction is considerable.
Drilling at the Limit—Can Your Top Drive Handle It?
Authors: Deutsch Eric 
Published: March 2009

Abstract
As deepwater drilling has advanced, the weight expected to be borne by a top drive has increased to levels at or near the load rating of the machine. The single load rating number normally associated with a top drive model (e.g. 1000 ton) is a nominal figure that may not apply to every operating situation. A typical top drive has two main load paths: hoisting and drilling. Hoisting load passes through the elevators and link hanger, while drilling load passes through the saver sub, IBOPs, and main shaft bottom end connection. Limitations inherent to rotary shouldered connections can lead to diminished drilling load capacity vis-à-vis hoisting. Further complicating matters is the fact that the drilling load path is governed by disparate API specifications: 7 and 8C. These two specifications provide different calculation guidelines with regard to safety factors and are subject to a certain amount of interpretation.
The end result is confusion about how much load a top drive can realistically handle. A 1000 ton top drive may not be officially rated to hoist 1000 tons through its IBOPs. Additionally, API sets forth a different load rating for the swivel bearing, so load rating for rotation differs from overall top drive load rating. This paper discusses the technical aspects of top drive load rating and clarifies the usable load capacity of a top drive in real-world conditions.