bluuebunny/crossref_metadata_2025_split huggingface dataset:
Overcoming Uncertainties Through Advanced Real-Time Wellbore Positioning in Kuwait: A Success Story
Authors: Jumah Saud , Saleh Khaled , Al-Mayyan Haithem , Al-Mudairis Fahad , Hawkins Don , Al-Abri Hakim , Martinez Pavel 
Published: February 2010

Abstract
Real-time multi-lateral wellbore positioning of horizontal wells for improved reservoir deliverability has been a revolutionary breakthrough worldwide. It has supported the efficient production of hydrocarbons from multiple thin layers within a reservoir to yield maximum recovery and to restrict water coning. Recent advances in real-time geosteering now enable, with even greater precision, successful targeting of "sweet spots" within a reservoir. These advances have the capability to open still more drainage volume for recovery of hydrocarbons.
Through successful teamwork from multidisciplinary professionals, numerous uncertainties and challenges were overcome using real-time geosteering techniques in conjunction with advanced logging-while-drilling (LWD) sensors and instrumented rotary steerable systems in Kuwait Oil Company's Magwa field. For this purpose, pre-well modeling, real-time geosteering, advanced LWD sensors, including azimuthal deep resistivity (ADR™) sensor, an azimuthal lithodensity (ALD™) sensor, instrumented rotary steerable systems (RSS), and real-time operation (RTO) services were used. The historically anticipated production rate was surpassed through the optimized placement of this well.
The outcome of this particular dual-lateral well using advanced real-time geosteering technology has led to development plans for additional multi-lateral wells in Kuwait. They will be targeted to the highest porosity and permeability zones within the upper compartments of the reservoir while avoiding the adverse water coning effects of wells drilled vertically or in the massive sand. This paper reviews the teamwork and deployment of real-time geosteering operations, as well as new generation LWD and RSS sensors, used to successfully improve reservoir deliverability.
Real-Time Well Tool Face Information Reduces Directional Uncertainty and Risks in Difficult Sidetracks in Gulf of Suez
Authors: Howes Thomas B. , Farouk Mohamed , Darwish Mohamed , Koroletz Wilhelm , Ismail Ahmed , Moustafa Amin , Heisig Gerald 
Published: February 2010

Abstract
To address risk and uncertainties in difficult sidetrack operations in the Gulf of Suez in Egypt, a new method was implemented to identify and control the direction of the wellbore during the whipstock exit, and close to the liner, where standard directional measurements are compromised due to magnetic interference. Bending moment sensors were placed directly above the motor and only 26 ft behind the bit. These sensors delivered two perpendicular bending moment measurements referenced to gravity high side. Transmitted to surface via mud pulse telemetry, the two signals were further processed to deliver the well tool face and – with the help of a mathematical BHA model – the dogleg severity of the well.
In one case the well tool face confirmed the orientation of the whipstock and the window milled. However, in a second case, the measurement revealed a 40 degree deviation from the original whipstock orientation. The well plan was immediately adjusted to compensate for this deviation from plan. The dogleg severity information gave improved azimuth control when steering away from the existing well in sliding mode. As a result, both sidetracks achieved their directional objectives and could be steered into the target. The directional estimates derived from the bending moment measurements were later confirmed by the first valid MWD surveys and by gyroscopic survey measurements.
The paper will start with a detailed description of the directional challenges in this application. It will then introduce the concept of the bending moment measurements and the derived directional information, well tool face and dogleg severity. After a description of the implementation and directional execution of the sidetracks, the paper will conclude with a discussion of the benefits and the potential of this new directional control method, which could result in a reduction or even complete elimination of gyro runs during similar casing exits and significant rig time savings.
Intelligent ESP System Enabled Effective Stimulation and Post Treatment Well Test: A Case Study of Restoring Production from a Horizontal Well in Belayim Marine Field
Authors: Soegiyono R. E. , Guichard A. M. , El Sonbaty A.. , Dilling L.. , Crema G.. , Pierfelici S.. , Mahmood A.. , Fawzy A.. , Abuzeid M. E. , El-Farahaty Osman M. M. 
Published: February 2010

Abstract
Intelligent artificial lift technology is increasingly being used in Belayim Marine Field to enhance the value of maturing assets and new development wells. Wells equipped with electric submersible pumps (ESPs) are particularly suited to this blend of old and new. For years, the performance of ESPs has been monitored and controlled from the surface to prevent early pump failure by adjusting the frequency of the signal sent to the pump's variable speed drive (VSD) motor controller. This adjustment has also been used to avoid under-loading an ESP and increase production volume. To find this optimal operating range, real-time data and modeling are used to design the pump to fit the specific requirement of each well.
Most recently, Belayim Petroleum has taken the concept a step further by deploying intelligent artificial lift in combination with stimulation technology aimed at reservoir management to help restore production from the 113-M-97-H well in Belayim Marine field, which is located in the central part of the Gulf of Suez, along the coast of the Sinai Peninsula. This new development well was drilled horizontally with maximum angle of 88°, and a 211 m. horizontal open-hole section was completed with 3.5-in. excluder screens. The well once achieved 22-hour good recovery at 550 BOPD. Then the production declined and the well was shut in due to low amperage, followed by no recovery caused by severe loss of circulation, which created a filter cake plugging the near wellbore pores. Complex stimulation treatment and flow, and well geometry and completion, as well as the offshore environment have complicated workover operations on this depleted reservoir and unproductive well issues. With intelligent ESP, a cost-effective stimulation was successfully deployed and enabled to evaluate production streaming data, such as pump intake pressure and temperature during the treatment across the horizontal section.
Already equipped with in-well electric power cables, protectors, and multi-sensors, as well as a power controller VSD at the surface, this intelligent ESP system also enabled clean-out process at different production rates. Once clean reservoir fluids were observed during the flowing period, the ESP was stopped for a pressure build-up. A post-stimulation well test was performed to evaluate the treatment's effectiveness before running the new completion, hence minimizing intervention time to restore production promptly, reducing rig time, and achieving optimum completion design for long-term productivity of the well.
Gulf of Suez Continuous Gas Lift Real-Time Optimization Strategy
Authors: Abdallah Yasser A. , Gaber Nabil S. , Saad EmadEldin A. , Bedair Elsayed A. , Soegiyono R. E. 
Published: February 2010

Abstract
The application of continuous-flow gas lift systems have been operating for over 40 years in Gulf of Suez Petroleum Company (GUPCO) offshore Gulf of Suez. Like any artificial lift method, it is to improve the productivity whilst ensuring the most effective use of the existing reserves. Continuous gas lift operations is favorable for these fields because of the flexibility in its production rates, ability to handle corrosive fluids, suitable for high temperature and high gas oil ratio wells, and compatibility with sand production. Some other real challenges facing the Gulf of Suez assets management besides keeping up production and maximizing reserves from mature fields are the ageing production facilities, and limited testing and data acquisition infrastructure. As more and more wells are completed with gas lift, the task of gas lift monitoring becomes more time consuming.
An important part of the gas lift optimization process is the effective gathering of live field data in order to establish the performance of the field and its individual well. A source of this information so far is a bunch of well files placed in the field and or head quarter offices. Because of inadequate infrastructure for an optimization and monitoring schedule, it is required to initiate a system with today's real-time data acquisition and data transmission technology, which provide an opportunity to implement the real-time production optimization effectively and remotely by means of satellite and web interface.
A pilot platform was selected to prove the concept of real-time production optimization. It is located in El-Morgan offshore field, approximately 160 miles in the south Gulf of Suez. The field consists of four (4) major platform complexes and 17 satellite platforms with over 80 current producers and around 50 injectors. Despite on-going operational difficulties and complexities, waterflood operations in this field indicate a successful exploitation of potential reserves. The field's cumulative production to date is 51% of its predicated Stock Tank Oil Initially in Place (STOIIP). Manual data gathering exercise is being implemented as a remedial solution to validate definitive benefits from the gas lift optimization process. The pilot began with a feasibility study for most reliable, safe and secured data acquisition and data transmission deployment to overcome the daily struggle of gathering sufficient, current and reliable data, and to better understand the field production potential. The strategy is further defined into several steps from efficiently monitor well behavior on a well by well basis, achieve full monitoring coverage for the field, provide quick response to well down-time, provide thorough review and analysis on well performance, hence give more time to gas lift engineers to look for other optimization opportunities around the field.
Latest PDC Technology and Optimization Process Enable Replacement of Multiple Impregnated and Roller Cone Bits with One PDC Bit Run
Authors: Foucault Hubert , Malagon Raul , Aliko Enis , Teelken Reina , Hitchman Ross 
Published: February 2010

AbstractThe Cambro-Ordovician formation in onshore Algeria consists of hard and abrasive sandstones that have proven challenging to drill. Up until now, no bit has completed the section in one run, and these formations have been considered beyond the limit of what is drillable by PDC cutters. Previous sections have used impregnated diamond and roller cone bits that achieved low penetration rates and required multiple bit runs. The impregnated runs require the additional cost of turbo drills or high-speed motors to deliver the rotation speeds necessary to achieve acceptable rates of penetration, while a bearing seal failure of a roller cone bit increases the risk of losing bit pieces in hole.The operator conducted an optimization process based on rock mechanics including an analysis of prior performances to conclude that the formation could be drilled more economically applying the recent advances in PDC bit technology. Collaboration between the bit manufacturer and the operator facilitated the implementation and development of the latest bit technology, including enhanced bit stability, improved cutter layout and more resistant cutters. After an initial, partially successful run, new bit improvements were implemented. The two subsequent runs completed their sections, enabling the operator to drill with one bit through what was previously a multiple-bit section. Rates of penetration were improved significantly over previous impregnated and roller cone runs. Requirements for down hole drive tools and bit trips were eliminated as was the risk of bit junk being left in hole.This paper outlines the process that led to improved understanding of the formation drill ability, the research and development behind this new bit technology, the continuous optimization of the specific bit, its field performance, and the resulting cost saving for the operator.
Fractured Reservoir Characterisation: A Fully Integrated Study, from Borehole Imagery, Cores and Seismic Data to Production Logs - Example of an Algerian Gas Field (Sbaa Basin, SW Algeria)
Authors: Panien M.. , Portier E.. , Marcy F.. , Ghilardini L.. , Le Maux T.. , Dehaeck T.. 
Published: February 2010

Abstract
GDF-SUEZ and Sonatrach will develop in partnership the main fields of the prolific Sbaa basin, SW Algeria. In this basin, the main gas levels comprise the Cambrian and Upper-Ordovician reservoirs, sealed and sourced by the Silurian "Hot Shales" Formation. During the exploration and appraisal phases of the project, an intensive drilling program, including coring, standard logging and imaging (FMI), following a 3D seismic campaign was performed.
Integrated study was done to investigate the suspected impact of natural fractures on the reservoir performances, to suggest potential geological drivers on fracture type (such as diffuse fractures and fracture swarms, if any) and on fracture distribution. The hydraulic properties of the fractures, based on available dynamic data were also evaluated. Indeed, accurate information on fault network and on fracture properties is essential to improve strategies for maximising hydrocarbon recovery, by optimising well location or directional drilling.
Various seismic anisotropy "fracture relevant" attributes (RMS, Coherence and Dip) were selected and jointly used in a multi-variable statistical process called Seismic Facies Analysis (SFA). This gave a preliminary interpretation of the seismic facies in terms of fracture density that was completed and validated with well data and curvature analysis. The curvature pointed out various scale lineaments fully consistent with previous work. It concludes on predominance of fault-related fractures. According to dynamic data, well productivity may be enhanced by fracturation by a factor up to 12.
The resulting fracture probability map was used to build a 3D fracture model with IFP and FracaFlow® software dedicated for fracture analysis and fracture modelling. For each well, a local discrete fracturation model was built. The length and intrinsic permeability of fractures were then calibrated using KH determined by well test interpretation and production log analysis. The final result consisted in computing the equivalent properties of the fracture network in each cell of the reservoir grid in order to perform the reservoir simulation. In this study, we present the results of production log (PLT) matched with success. The same fracture parameters were also used to match consistently the production log of the other wells.
The integration of a wide type of data to analyse the natural fractures of this Algerian gas field leads to a fully consistent and well-constrained fracture model.
SMART™ Technology Application, Preparation and Implementation Case History
Authors: Abd El Raheem Taher Ali , Hassaballa Sherif Aly , Pyott Gary 
Published: February 2010

Abstract
Maximizing the recoverable hydrocarbon reserve and reducing both the capital & operating cost are always challenges. One of the tools to achieve the above targets is to apply the smart completion technology. Application of a SMART™ completion represents a significant challenge, especially if it is combined with gravel packing in high rate producing wells. The equivalent production area between the SMART™ well completion component and the inner diameter of the screens represent a challenge to ensure that contributions from all the zones are possible without scarifying production. In addition, the affect of possible sand production and the affect on the overall system needed to be addressed.
Rashpetco have decided to apply this SMART™ technology as base case for the development of two offshore fields in the Mediterranean. One of the developments is from a remotely operated platform and the other is from a subsea field. Both of the developments will produce from two different horizons. The development selection was based on a comparison with other completion alternatives, the evaluation of the risk associated with using this relative new technology and the cost impact versus change in ultimate recovery.
Using SMART™ completion will minimize the number of wells to be drilled to obtain the same recovery factor and will minimize any intervention to open the conventional sliding sleeve. It will also help minimize water production at sand face, which will reduce the cost of expanding water separation facilities and will have a positive impact on the vertical flow performance. It should be noted that the SMART™ completion could be either on/off or chocking type. The selection will be based on the driving mechanism and the reservoir performance
This paper describes the process of preparation and implement of the SMART™ system for both platform and subsea developments. It will also show the results and benefits
Borehole Strengthening and Injector Plugging – The Common Geomechanics Thread
Authors: Loloi Mehdi , Zaki Karim S. , Zhai Zongyu , Abou-Sayed Ahmed 
Published: February 2010

Abstract
The high cost of offshore drilling and the safety aspects of penetrating depleted reservoirs bring borehole stability issues to the forefront of resource development. Drilling in deepwater fields, depleted reservoirs and/or low stress environments requires careful assessment of mud weights. Higher collapse pressures combined with lower fracture gradients limit or eliminate mud weight windows and lead to tight holes or lost circulation. Extended-reach wells require minimization of the number of casing shoes to reach the deeper targets. The need for long, open sections while drilling imposes restrictions on mud windows. Borehole strengthening has become the most effective method to address borehole stability in such circumstances.
In this paper, we provide geomechanics insights from the large knowledge base on waterflooding and injector performance to improve the practice of wellbore strengthening. The petroleum industry has morphed over its long history through fewer inventions but a long list of innovations derived from lessons learned from one sector to benefit another. Injector plugging, a nuisance to production/operation engineers, illustrates such an example. The vast amount of knowledge provides the fundamental reasoning and rationale for optimizing wellbore strengthening. Fractured injector geomechanics are extended to improve wellbore strengthening procedures. Strengthening is implemented through creation of plugged minifractures to raise loss circulation pressures. The mud contains particles to mitigate unstable fracture extension created by using higher mud weights. The particles deposit and plug initiated fractures and prevent further propagation. The propagation pressure is raised significantly and lost circulation stops. In the presented model, the stable fracture length and width are related to a given mud weight and rock characteristics. Accordingly, the plugging media (particle) size is optimized based on the fracture geometry and leakage scenarios. The model results are field-verified and demonstrate how the borehole stability problem could be optimized with proper design.
Merging 3D Seismic Data for IR Field Development
Authors: Widjiastono Agus , Aljilani Almhedwi , Hamrbtan Nasser 
Published: February 2010

Abstract
The development plan of IR field, located in Murzuk basin, SW Libya was approved in August 2007. The discovery well was drilled on NC186 block in 2005. Then, it was followed by appraisal wells on both NC186 and NC115 blocks in 2006. IR field straddles blocks NC115 and NC186 that have different partners and petroleum contracts, although the same development and production operating company. The field is relatively complex due to the reservoir heterogeneity of Ordovician sandstone Mamuniyat in the area of interest. 3D seismic is one of the important datasets for selecting producer and injector locations, developing the field effectively and reducing the risk associated to drilling those development wells. No specific development 3D seismic was acquired for IR field yet. The current available 3D cube is the result of merging two exploration 3D seismic datasets: NC186-2003 and NC115-2006. This cube has been used as the basis for the interpretation during the Phase 1 of IR development plan. Up to now, several well results deviated from the prognosis in terms of reservoir top depth, thickness and quality. Those deviations are indicative of a seismic dataset not robust enough for detailed reservoir interpretation. A further investigation identified different kinds of hiccups on transit time, amplitude and phase mismatch with borehole seismic data, and the footprint of the merge boundary of 2003 and 2006 exploration 3D seismic cubes. Those identified flaws have to be addressed prior to further use of the merged 3D cube as a predictive tool for main reservoir depth, presence, lateral extension and properties. This paper will present the efforts and strategies adopted to resolve the encountered inconsistencies and artifacts, and improve the quality and reliability of the merged 3D cube. Therefore, the enhanced quality 3D cube can be used for reliable and consistent reservoir characterization to support the Phase 2 of IR development plan in year 2010.
Structural Characterization, Development Optimization and Increase of OOIP in a North African Oil Field (SW Libya) Through Enhanced Seismic Methodology
Authors: Gómez Nacarino Cándido , Abusaq Walid , Ranero Alvaro , del Rio Carlos 
Published: February 2010

AbstractB-NC186 field is located in the Murzuq Basin, SW Libya. Fifteen wells have been drilled up to July 2009; seven of them consisting of a pilot hole prior to the drilling of the horizontal main hole.The producing reservoir is the Upper Ordovician Mamuniyat Formation. The field is conformed by the oil accumulation in one of the glacial palaeovalleys filled by the Mamuniyat Formation which was eroded and capped by the major Silurian marine transgression and gently deformed during later orogenic phases. Main regional seal is Silurian age Tanezzuf shale. Tanezzuft basal Hot Shale member acts as the main source rock in the Murzuq Basin.150km2 of 3D reprocessed seismic data were reinterpreted in 2008 in preparation of an aggressive drilling campaign. The main objectives of that reinterpretation were: Exhaustive QC of the existing data: seismic versions, well coordinates, KB elevations, markers, deviation surveys and VSP surveysMap in detail the fault network affecting our reservoirEnhance the position of the boundaries of Hawaz palaeohighsPerform a reliable depth conversion with the objective of identifying untapped upside potentialA detailed analysis of seismic attributes: Grid based, Variance Cube and Volume attributes (Dip, Azimuth and DipAzi combined), made possible the definition of the fault network affecting Mamuniyat reservoir.Some interpretation principles were established in order to accurately define the limits of the Hawaz palaeohighs optimizing the location of producers nearby B-4 Hawaz palaeohigh.A new NW-SE oil-bearing structural trend was discovered between B-4 and J Field palaeohighs. Sedimentologically this structural high constitutes a deep palaeovalley containing more than 1,000ft of clean Mamuniyat sandstone (well B-14H pilot hole). The OOIP of this southwest extension amounts to more than 100mmbo.An unexpected low velocity anomaly was encountered after B-13H pilot hole well results. The VSPs acquired on the pilot holes of wells B-13H and B-14H revealed that wrong dynamic corrections were applied for Top Mamuniyat due to the thickness reduction of Tanezzuft shale along this trend. Consequently, the seismic velocity was overestimated and Top Mamuniyat seismic reflector was interpreted deeper than found by the VSP.