bluuebunny/crossref_metadata_2025 huggingface dataset:
Smart Well Technology in Daqing Oil Field
Authors: Xu Dekui , Zhong Fuwei , Wang Fengshan , Wang Jinyou , Li Yan , Xiaoyu Xu , Jiankun Zhou , Pan Weiguo , Xin Liu , Lin Zhongchao , Gan Lina
Published: November 2012

Daqing oilfield has entered the late period of extra high water production. With the development of horizontal well technology, coning of injected water is one of the most important production problems in the Daqing oilfield. The water cut of many wells in old depleted areas is more than 80%, and still rising. With the use of horizontal well technology in depleted areas, the problem will continue. An adjustable water system or smart well (intelligent completion) technology is urgently needed to solve the practical production problems in this oilfield.

This article first identifies the smart well (intelligent completion) technology, and the major companies using it. Secondly, the paper shows the development of smart well technology in China, the reason why we use smart well technology in the Daqing oilfield, the adjustable water cut system in the Daqing oilfield, and the application of smart well technology in the Daqing oilfield. Finally, a smart well is introduced, and some of advanced downhole devices and the prospects for their application in the Daqing oilfield are detailed.
Evaluation of Nonreactive Aqueous Spacer Fluids for Oil-based Mud Displacement in Open Hole Horizontal Wells
Authors: Osode Peter , Otaibi Msalli , Moqbil Khalid Bin , Kilani Khaled , Azizi Eddy
Published: November 2012

Reactive mud cake breaker fluids in long open hole horizontal wells located across high permeability sandstone reservoirs has had limited success because they often induce massive fluid losses. The fluid losses are controlled with special pills, polymers and brine or water, causing well impairment that is difficult to remove when oil-based mud (OBM) drill-in fluids (DIFs) are used. This situation has resulted in the drive for an alternative cleanup fluid system that is focused on preventing excessive fluid leak off, maximizing the OBM displacement efficiency and allowing partial dispersion of the mud cake for ease of its removal during initial well production. The two-stage spacer application is composed of a nonreactive fluid system, which includes a viscous pill with nonionic surfactants, gel pill, completion brine and a solvent.

Extensive laboratory evaluation was conducted at simulated reservoir conditions to evaluate the effectiveness of the OBM displacement fluid system. The study included dynamic high-pressure/high temperature (HP/HT) filter press tests and coreflood tests in addition to wettability alteration, interfacial tension and fluid compatibility tests.

The spacer fluid parameters were optimized based on wellbore fluid hydraulic simulation and laboratory test results, which indicated minimal fluid leak off and a low risk of emulsion formation damage. Three well trials were conducted in a major offshore field sandstone reservoir drilled with OBM. All three trial wells (one single and two dual laterals), which were treated, have demonstrated improvement in production performance. This paper will discuss in detail the spacer fluids optimization process, laboratory work conducted and the successful field treatments performed.
Innovative Process to Ensure Efficient Multiple Stage Fracturing Treatments
Authors: Hakami Ibrahim M. , Gomez Francisco A. , Asiri Khalid , Kharrat Wassim , Baez Fernando , Vejarano Eduardo , Ahmed Danish
Published: November 2012

Multiple-Stage-Fracturing (MSF) is a common practice today as it allows controlling the stimulation of long intervals, and improves the ultimate recovery of hydrocarbons. Multi-Stage-Frac-Completions (MSFC), designed with Open-Hole-Packers (OHP) and Frac-Ports (FP), are currently implemented by Saudi Aramco to perform such operations in gas wells. The integrity of the OHP and the functionality of the FP are vital for an effective fracturing treatment.

During a MSF treatment, the bottom FP is opened first by pressurizing the MSFC to a predetermined pressure. After pumping the first fracturing stage, a ball is dropped to isolate the lower zone, open the second FP with pressure, and enable the second fracturing stage. This step is repeated till all FP are opened and corresponding zones are fracced one after the other. In every step of pressurizing the MSFC, a drop in pressure is automatically interpreted by the assumption that the adequate FP is open and that the MSFC is ready for another fracturing stage. The OHP are also assumed to be holding without performing any downhole checks. Opening the wrong or multiple FP at the same time, having a leaking OHP will certainly lead to undesired results and possible expensive remedial rig interventions. Therefore downhole monitoring is needed to confirm that the MSFC is ready before every fracturing stage.

The Fiber-Optic-Enabled-Coiled-Tubing (FOECT) can be used as monitoring system by measuring the Distributed-Temperature-Survey (DTS), which is interpreted realtime to confirm which FP is open, and if OHP are sealing.

This paper demonstrates through two case studies how DTS was used to assess the readiness of the MSFC to proppant fracturing treatment. An innovative profiling process in MSFC is proposed to replace assumptions by measured facts, to give client confidence on when to start the fracturing treatment, and to eliminate unnecessary operation by detecting MSFC hardware malfunction.
An Advanced Special Core Analysis Study for a Middle Eastern Carbonate Field
Authors: Lun Lisa , Guice Kyle , Kralik Jim , Meissner Jon , Kenawy Maher , Kalam Zubair , al-Dayyni Taha
Published: November 2012

A novel special core analysis (SCAL) study was conducted utilizing samples from a Middle Eastern Carbonate Reservoir in order to gain insights into flow behavior across stylolitic intervals. This study included relative permeability and capillary pressure measurements performed on individual core plug and core plug composite samples, as well as a unique waterflood experiment on a four-inch diameter whole core composite. All laboratory flow measurements were performed at reservoir conditions of temperature, pressure, and net confining stress. As part of this study, it was demonstrated that wettability restoration remains a significant challenge for carbonate core samples, with implications for coring and core analysis program design and interpretation of historic SCAL data. Core-scale simulation using measured relative permeability and capillary pressure data along with whole core rock properties provides an opportunity to validate laboratory results across laboratory scales and can also serve as an intermediate to mechanistic modeling studies at larger scales. In this paper, the novel technical approach and significant findings for the special core analysis study are presented, with implications for modeling of displacement processes across stylolitic intervals in complex carbonate reservoirs. General recommendations for the design of special core analysis programs are also presented.
A New Method to Predict Performance of Gas Condensate Reservoirs
Authors: Al-Shawaf Ali , Kelkar Mohan , Sharifi Mohammed
Published: November 2012

Gas condensate reservoirs differ from dry gas reservoirs. Understanding of phase and fluid flow behavior relationships is essential if we want to make accurate engineering computations for gas condensate systems. Condensate dropout occurs in the reservoir as the pressure falls below the dew point, as a result of which, gas phase production decreases significantly.

The goal of this study is to understand the multiphase flow behavior in gas condensate reservoirs and, in particular, focusing on estimating gas condensate well deliverability. Our new method analytically generates inflow performance relationship (IPR) curves of gas condensate wells by incorporating the effect of condensate banking as the pressure near the wellbore drops below the dew point. The only information needed to generate the IPR is the rock relative permeability data and Constant Composition Expansion (CCE) experiment.

We have developed a concept of critical oil saturation near the wellbore by simulating both lean and rich condensate reservoirs and observed that the loss in productivity due to condensate accumulation can be closely tied to critical saturation. We are able to reasonably estimate re-evaporation of liquid accumulation by knowing the CCE data.

We validated our new method by comparing our analytical results with fine scale radial simulation model results. We demonstrated that our analytical tool can predict the IPR curve as a function of reservoir pressure. We also developed a method for generating an IPR curve by using field data and demonstrated its application by using field data. The method is easy to use and can be implemented quickly.
Workflow for Asphaltene Precipitation Assessment and Mitigation Strategies
Authors: Zhou Honggang , Passade-Boupat Nicolas , Gonzalez Marianna Rondon
Published: November 2012

The prediction of the risk of asphaltene precipitation is an important topic in the petroleum industry. It usually requires representative samples and measurements using specialized, high-pressure equipment, and may have to be performed on many different fluids from various reservoirs. Of the many fast screening methods have been proposed, most of them only take into account the hydrocarbon phase without any investigation on the actual asphaltenes in the crude, and may lead to erroneous predictions.

This paper presents a universal approach of the risk of precipitation of asphaltenes.

A new experimental way to perform fast screening of asphaltene instability is proposed based on relevant solubility properties of the asphaltene fractions. It is based on two major parameters: the live oil solvent properties (based on PVT analyses) and the actual solubility of asphaltene fraction, through an easy characterization procedure that examines the solubility of asphaltenes in heptane/toluene mixtures. In field development projects, this method, which can be performed on dead oil samples, helps limit the investigation to fluids that present a real risk of asphaltene precipitation.

If a precipitation risk is stated, two paths are followed in order to estimate the risk level, and to prepare a mitigation strategy. Additional tests, performed on pressurized representative samples or taking into account reorganization of asphaltenes from different fluids, will help to define the severity of the risk. For mitigation, an advanced test set-up has been developed, which facilitates evaluation of the efficiency of chemical additives to prevent plugging under flow conditions of fluids above the asphaltene precipitation threshold. Depending on the crude oil, the severity of the precipitation conditions, and the nature of the additive, the blocking of a capillary tube can be delayed or prevented.
A Break Through In Monobore Completion System by Using New Design "One Run" Upper Completion System
Authors: Ghayoomi T. , Hashemi M. H. , Karami P. , Javadian M. , Ueland G. , Ibragimov A. , Delavar A.
Published: November 2012

Majority of the high rate gas wells in the world are completed with Monobore completion system. The conventional sequences of running Monobore completion in giant gas field of SouthPars are in three steps: Run No. 1 which includes running Liner and liner hanger by drill pipes (DP) and normally followed by cementing behind liner, Run No. 2 which includes Running Tie Back production Packer with 15 ft Polished Bore Receptacle (PBR)by setting tool and DP and finally Run No. 3 which includes running completion string with upper seal stem and at the end complete the well with proper space out. Running of tie back production packer with setting tool and DP in one step and running upper seal stem by tubing in last step has some concerns (More Rig time, cost, safety, etc).

Feasibility Study and research was carried out to check the possibility of combining the run No. 2 and 3 together.

A new method has been developed and after successful surface test it was run in one of gas wells in South Pars giant gas field in Persian Gulf. All pressure tests after installation were satisfactory. This procedure saved almost 1.5 day of rig time and protected seals against mechanical damage while running in the hole.
Martin Linge Electric Power from Shore
Authors: THIBAUT Edouard , LEFORGEAIS Bruno
Published: November 2012

Martin Linge offshore gas field (formerly named Hild) is located on the Norwegian sector of the North Sea, southwest from Oseberg. The field development comprises a platform with a jack up rig and Floating Storage Offloading unit. This offshore development will be supplied with electric power from shore, through a High Voltage AC submarine cable.

With a step out distance of 170km and a design power of 55MW, this will be the world's longest AC submarine cable power supplying an entire offshore Oil and Gas platform from the shore.

This paper presents the Martin Linge project, it discusses the criteria considered to select a power from shore instead of an offshore Gas Turbine power plant which is the current practice in the offshore Oil and Gas industry.

And since in a first approach, for such long step-out distance, the choice of power from shore would be to select a DC transmission line, the paper discusses the design, system approach and main technical challenges of this long step-out AC transmission development.

Finally, the paper gives an operator's viewpoint as to the way forward.
Pushing-up Field Ultimate Recovery to Top Quartile through Infill Development - A Case Study of a Carbonate Waterflood Field
Authors: Garimella Sai , Kharusi Ahmed , Wahaibi Hamed , Goossens Peter , Warrlich Georg , Kindy Zaher , Harris Jeremy , Al Lamki Ali
Published: November 2012

PDO has a diverse portfolio of mature fields undergoing waterflood. These fields open-up an additional opportunity through infill drilling for enhancing the ultimate oil recovery. It has been established in the oil industry that increased well density does not only result in acceleration but will also lead to incremental recovery. This paper demonstrates the approach taken for identifying and maturing an infill development in a Shuaiba matrix carbonate reservoir within a thin oil column. The case study field has been developed predominantly with single long (~ 1.5 km) horizontal oil producers (lifted with ESPs) & water injectors in a Producer-Producer-Injector (PPI) pattern with a ~60 m spacing between Producer and Injector (P-I).

The development team executed additional appraisal activities in parallel with implementing the field development plan. Seismic inversion was updated with the new well results which improved porosity prediction in un-drilled areas. Based on acoustic impedance guidance, appraisal wells have been drilled with encouraging indications in terms of producibility and opened new areas for further development. The history matched simulation model results showed that 120 m P-P-I spacing would recover 25% of in place volumes compared to 60 m P-P-I spacing with an ultimate recovery factor (URF) of 45%.

The key success factors for the infill development are (1) well placement with geosteering, (2) balancing appraisal with development and (3) continually updating static and dynamic models. This is done to support development decisions such as well sequencing & placement, drilling activity and surface facilities expansion. The key learning from this case study is that developing fields initially with twice the proposed development spacing, nevertheless following the optimal water flood pattern, is the best way for appraising the whole field rapidly. This allows time to gather much needed information ahead of making tactical investment decisions on long lead-time surface facilities.

The case study field development & maturation activities enabled pushing-up the ultimate recovery above 33%, bettering the top quartile recovery factor and achieving a sustained oil production forecast of above 20,000 units for the forthcoming 6+ years. The methodology developed and presented in this paper could be adopted for typical water flood developments.
Leak Detection by Temperature and Noise Logging
Authors: Mohamed Ihab Nabil , El-Hamawi Mohamed , Al Hassan Rasheed Ahmad , Aslanyan Arthur , Filenev Maxim , Aslanyan Irina , Bargouthi Jamal , Salim Bassam
Published: November 2012

Monitoring and handling Sustainable Annulus Pressure (SAP) is a daily challenge in today's oil and gas industry. Well integrity failure can affect production and the environment and, consequently, lead to high economic losses from fixing the resulting damage. Once SAP is confirmed, its source should be located and shut off as soon as possible. The biggest problem is leaks behind multiple barriers, which are not clearly seen in conventional temperature and noise logs.[1] However, recent developments in temperature and noise logging tools and interpretive techniques have been rewarded by achieving high resolution and sensitivity enabling the detection of previously undetectable leaks.[2] This paper describes two cases of integrity failure in the B and C annuli detected by the new integrated high-precision temperature and spectral noise logging technique, or HPT-SNL.
Anti-Corrosion Performance of Polyaniline Modified Ferrites
Authors: Mittal Vikas , Chaudhry A. U. , Khan M. I.
Published: November 2012

In this work, spinel based zinc, nickel and zinc-nickel ferrites were synthesized and modified with oxidatively polymerized polyaniline-phosphate. The corrosion protection behavior of these polymer modified ferrites was investigated after formulating with acrylic primer and subsequent coating on carbon steel panels. Salt spray test revealed that among all the anticorrosion pigments, polyaniline modified zinc-nickel ferrites showed significantly improved anticorrosion properties. Incorporation of PANI modified zinc and nickel ferrites in the primer coatings also improved the anti-corrosion performance. Pure PANI coatings suffered from adhesion problems with the substrate, which were markedly improved when PANI layered ferrites were introduced in the coatings.
Public, Private, or Hybrid? What the Upstream Oil & Gas Industry Can Learn from Other Sectors about "the Cloud"
Authors: Perrons Robert K. , Hems Adam
Published: November 2012

Despite the compelling case for moving towards cloud computing, the upstream oil & gas industry faces several technical challenges—most notably, a pronounced emphasis on data security, a reliance on extremely large data sets, and significant legacy investments in information technology (IT) infrastructure—that make a full migration to the public cloud difficult at present. Private and hybrid cloud solutions have consequently emerged within the industry to yield as much benefit from cloud-based technologies as possible while working within these constraints. This paper argues, however, that the move to private and hybrid clouds will very likely prove only to be a temporary stepping stone in the industry's technological evolution. By presenting evidence from other market sectors that have faced similar challenges in their journey to the cloud, we propose that enabling technologies and conditions will probably fall into place in a way that makes the public cloud a far more attractive option for the upstream oil & gas industry in the years ahead. The paper concludes with a discussion about the implications of this projected shift towards the public cloud, and calls for more of the industry's services to be offered through cloud-based "apps."
Challenges in Developing Attic Oil under a Giant Gas Cap, Advances in Modelling and Completion Strategy, a Well Case
Authors: Xu Siqing , Kshada Ali , Mukhtar Muhammad , Abdou Medhat , Amiri Abdel Hameed , El Wazeer Fathy
Published: November 2012

The reservoir under consideration, Reservoir A of the Lower Cretaceous age, Kharaib formation is a complex giant carbonate reservoir within an onshore field in Abu Dhabi. Substantial volumes of oil remain to be developed from the Attic area directly underneath the giant gas cap. 4 Attic wells were drilled since 2005 and they have all experienced gas breakthrough. To better manage Attic well production and optimize attic development, one of the attic wells has been selected for a pilot to install Integral Control Valves (ICV). The aims and objectives are for down hole zonal gas production control leading to optimized single well recovery while respecting facilities gas handling constraints. In parallel, two long horizontal wells are being drilled next to the pilot well to test the alternative concept of low production drawdown for gas breakthrough control.

This paper presents the design and detailed modelling study carried out for the ICV pilot well and the two long horizontal wells.

The ICV pilot completion design is described. The technology include swellable packer, inflow control valve (ICV), fiber optic DTS (Distributed Temperature Sensing). The open hole will be segmented into 3 sections using fed through swellable packer technology to pass fiber optic lines and install one ICV gross each section. The overall aim is to enable well GOR control, reduce project cost, maximize production and minimize any future rig intervention cost of shutoff at specific section.

A detailed single well model was developed within the 3D full field model. The well model was history matched, including PLTs and saturation logging. For ICV installation planning, a full range of sensitivity and uncertainty analysis was performed to assess likely impact. In particular, the impact due to potential faulting/sub-seismic faults was assessed. The model was also used to define data acquisition planning post ICV installation

The early production performances from the ICV pilot well are presented. For the two long horizontal wells, well design considerations are presented.

Plan for continued monitoring of the 3 wells are shown, with the aim of helping to optimize attic oil development.
Best Practices of Asset Management Process Supported by Reliability Analysis
Authors: Al-Adwani Adnan Eid , Kapavarapu Venkata Madhusudana
Published: November 2012

Reliability engineering approach was selected for optimizing the Gas Dehydration unit performance in BS-140/150 facilities to meet Asset Management process supported by Reliability Analysis for Gas dehydration units. Event log data collected for the system from March 2008 to March 2011 was analyzed using weibull ++ event log portfolio. Reliability Block diagram was developed for the gas dehydration and glycol regeneration system. The failure/repair distribution parameters were derived from the event log analysis. Reliability, availability and Maintainability values were derived from the simulation of the block diagram in "Block Sim" software. Exponential model was used for the analysis; since the temperature increases exponentially when the glycol cooler performance degrades. This leads to major impact on moisture increases in the gas export. Fault Tree Analysis was carried out for entire gas dehydration functional failure. Objective of this FTA was to identify the basic equipment responsible for the functional failure.
Immiscible WAG Injection Pilots Performance and Lessons Learnt in Carbonate Reservoir. Onshore Abu Dhabi Oil Field, United Arab Emirates
Authors: Al-Shamsi Hanaa S. , Abdulrahman Abdul Samad , Al-Ameri Ammar F. , Al Katheeri Abdulla B. , Sajeel Kashif , Al-Yaqoubi Amena
Published: November 2012

This paper reviews the performance of two immiscible Water Alternating Gas (WAG) pilots in W Field located in onshore Abu Dhabi- UAE. The main oil bearing reservoirs in the W Field are in the X, Y, & Z Zones. In August 2007, a gas injection pilot in Zone X was converted to a three-month cycle WAG pilot. The next month, a water injection pilot in the same zone was also converted to a three-month cycle WAG (Water Alternating Gas) pilot. The gas, water and WAG injection pilots were designed to increase sweep efficiency and optimize oil recovery from Zone X. The pilots are due to fulfill their objectives by year end 2012. Extensive monitoring programs were implemented in order to assess the performance of the pilots. These programs included frequent pressure measurements (BHCIP, PBU and PFO), production testing, cased-hole logging (RST/CNT/RPM/TDT), Flagship-PLT, PNL and Tracer injection monitoring. The results of the monitoring programs and the lessons learnt are discussed in detail. These results form the basis for the development of Zone X full field development plan. Immiscible WAG injection for 5 years showed improvement in sweep efficiency and recovery in Zone X. Field development plan considered drilling 8 WAGs wells in near future.
Challenges and Opportunities in Sour Gas Developments
Authors: Verlaan Cor , vd Zwet Gerard
Published: November 2012

To satisfy the growing global gas demand more reservoirs with sour contaminants (up to 40% of H2S and significant CO2) will be developed. Worldwide more than 1600 TCF of Sour Gas is anticipated. Shell has more than 60 years of experience in sour gas processing, ranging from the first facilities installed in Jumping Pound, Canada, to recent projects under development in Kazakhstan and Oman. This paper will describe a number of challenges and opportunities associated with development of "sour" projects.

The fact that H2S is lethal at low concentrations and highly corrosive in the presence of CO2 and/or (salty) water indicates that safety is a main driver in these projects. It is of crucial importance that the H2S is contained and that plant integrity is assured through tightly controlled maintenance programs.

Product specificationsfor produced gas and hydrocarbon liquids are ever tightening and legislation on emissions are becoming more stringent. Deep removal of H2S and other sulphur components like mercaptans and carbonyl sulphide is required. This increases the complexity and therefore cost of the sour gas processing facilities, which must compete with production from sweet gas in the region/country or alternatives such as LNG import. Technology innovation as well as smart integration of technologies are essential for the cost effective development of sour gas assets ensuring all specifications and emission requirements are met. Several examples of these technology innovations will be presented in this paper.
Common asset modeling and data integration as a foundation for field surveillance and performance improvement
Authors: VERBRUGGE Eric , DELESALLE Hervé , HANSEN Ralph
Published: November 2012

By creating a common view on field operation data, harmonizing the language within a site and from site to site, it becomes possible to work from different locations towards common objectives, ensuring the same understanding of "what goes on" on site. This provides an opportunity for rethinking competences, roles and distribution of responsibilities within the organization.

Total has developed a methodology to build such a view, based on a "Common asset model" and a "Field Monitor Platform".

The "Common Asset Model" is a Rosetta Stone for field operations data; it contains a description of the field equipment that is comprehensible to engineers in all disciplines contributing to field performance management. The naming of equipment, the attached information, as well as the associated semantic metadata offer a clear vocabulary shared by everybody in the field. This ensures that data is used in a consistent and appropriate manner, according with its nature, its actual source, its time granularity, the process that has built it...

The "Field Monitor Platform" provides a unique entry point for end-user applications to access all field operation data actually stored in the multi-disciplinary IT systems. End-user applications could be monitoring tools, calculations, event handling or simulation tools. The system relies on virtual integration as it only holds pointers to data within its official repository and delivers it directly from the original source.

The Field Monitor Platform has been industrialized for use in Total fields operations with a first deployment in the Gulf of Guinea.

The main results of this effort are:

A new robust methodology to define and manage a common asset model An innovative IT system ensuring efficient data integration A clearer understanding of the detailed monitoring requirements of an asset in general, and of the nature of transverse decision making in particular.
Impact of Asphaltenes Deposition on Completion Design for CO2 Pilot in an Onshore Abu Dhabi Field
Authors: Abdallah Dalia
Published: November 2012

Gas injection is one of the most common methodologies for Enhanced Oil Recovery (EOR) in the oil and gas industry. One of the challenges associated with gas injection, e.g. natural gas, CO2 and N2, is potential asphaltenes precipitation and subsequent deposition causing blockage throughout the production system. It is crucial that precipitation of asphaltenes is identified early in the planning stage of any EOR project so that mitigation strategies are put in place to avoid negative impact on well performance.

A line-drive pattern CO2 pilot is planned in a super giant field A onshore Abu Dhabi and hence single phase bottomhole samples were collected from a nearby well to evaluate asphaltene stability under CO2 gas injection. This paper presents the results of the lab work that clearly indicate no asphaltene deposition problems during natural production; however, asphaltenes will precipitate when CO2 is mixed with the crude at mole fractions as low as 0.2. Based on the experimental results and on field results from another CO2 pilot in field B, which experienced asphaltene deposition problems, it was deemed necessary to include provisions for continuous downhole chemical injection of asphaltene inhibitors in the CO2 pilot producers for field A.

The challenge is to combine the requirements to prevent CO2 corrosion and to prevent asphaltene deposition in the well. The paper describes the different completion design options that can be used to achieve the desired target taking into account the cost impact. The designs incorporate combinations of different tubing materials and chemical injection options with pros and cons to using each, keeping in mind the reservoir monitoring requirements that can add more constraints to the completion design.
Pore Pressure Prediction Using High Resolution Velocity and Acoustic Impedance in a Complex Field
Authors: Thakur Ram Kumar , Angstadt David M. , Chakraborty Kalyan , Kelsch Ken D.
Published: November 2012

Pore pressure prediction for exploratory deep Paleozoic well to avoid kicks, blow-outs, borehole instability and to design safe mud weight during drilling phase is a major challenge due to unavailability of deep well informations in South Fuwaris field, Kuwait. The problem was resolved integrating acoustic impedance volume derived from innovative seismic inversion on Prestack 3D Q-Land seismic data and geomechanical model with deeper pore pressure trend from drilled well data.

The Q-land data with exceptionally clean, high signal to noise ratio, reliable amplitude, stable phase and wide range of frequency with high trace density facilitated reliable inversion for prediction of reservoir properties from seismic. The high resolution is achieved through global optimization to a single non-linear objective function, which provides the optimum positioning of the layers and 3D multi-trace damping of the random-noise. The low frequency model, a prerequisite for seismic inversion was built with densely sampled stacking velocity constraining on seismic horizons and wells.

The most popular Bower's method, accounts for Loading (under-compaction) and Unloading (fluid expansion ) was applied to estimate Bower's parameters by cross-plotting velocity against effective vertical stress for drilled well - "A". The velocity reversal at Sargelu formation was confirmed with kicks in this well which was also cross validated with nearby Humma wells.

The pore pressure and frac gradient were estimated along proposed exploratory well with the trend developed at known shallower well "A" which was found to be in conformity with regional trends. The lithology predicted along proposed boreholes in order to design mud weight plug and sanctity was reviewed at Top lithological markers using pseudo porosity logs derived with multi-attributes using neural network technique.

This paper presents an integrated approach of pore pressure prediction for drilling deep exploratory well to minimize drilling risks.
The Impact Of Completion Related Pressure Losses On Productivity In Shale Gas Wells
Authors: Jackson Gregory , Rai Rakesh
Published: November 2012

Transient linear flow diagnostic plots in shale gas wells often exhibit a positive y-intercept and may mask the early transient linear flow regimes because of non-reservoir pressure drops. Increased completion resistance reduces the peak production rate early in the life of a well impacting NPV. The shale gas industry is very early in the research required to distinguish the individual contributions of completion resistance, e.g. poor fracture conductivity, near-perforation damage or choke skin, and fracture face damage skin. Many of these phenomena can be diagnosed in production wells using unique shape(s) from various diagnostic plots allowing for analysis of completion effectiveness.

Mechanistic reservoir simulations were used to generate diagnostic plot signatures for low conductivity fractures, choke skin, and near fracture face damage. subsequently, the corresponding signatures were compared with a large database of shale gas wells in numerous plays across North America to aid in the fingerprinting of these non-reservoir pressure losses. Only low fracture conductivity, not choke skin, can have a quarter slope. Near fracture face damage results in two distinguishable linear trends, one of the damaged region and the other for the matrix.

Completion skin diagnosis is a way of evaluating fracture efficiency by identifying the root causes of the non-reservoir pressure losses so as to mitigate them in the future. The following presents a catalogue of signatures that enables greater diagnostic capabilities to classify non-reservoir pressure losses. The study is the first comprehensive cause-by-cause look at completion damages with an emphasis on identification and diagnosis in shale gas wells.
Enhancing Vertical Seismic Resolution by Spectral Inversion
Authors: Kirchberger L. , Spitzer R.
Published: November 2012

Vertical seismic resolution quantifies the ability to distinguish between two close seismic events generated at different depths. A typical seismic dataset with a dominant frequency of 30 Hz allows the separation of top and base boundaries of a 25-meter thick reservoir layer. However, very often hydrocarbon bearing reservoirs are significantly thinner and, therefore, the vertical seismic resolution has to be increased in order to image and characterize those thin reservoirs properly.

The present study illustrates the application of spectral inversion technique based on high-resolution spectral decomposition offered by Lumina Geophysical, LLC. Spectral inversion can be described as a sparse-spike inversion driven by geological assumptions. It keys on local frequency spectrum obtained by spectral decomposition. Theoretically, a high signal-to-noise ratio and the exact knowledge of the seismic wavelet at reservoir level yield seismic resolution far below tuning thickness.

OMV chose to apply spectral inversion to various datasets recorded in Kazakhstan, West of Shetland and in Austria, covering different geological settings (e.g. channel features, sub-seismic faulting). Furthermore, a synthetic dataset has been designed and examined to illustrate benefits and pitfalls of the methodology. Each recorded seismic dataset showed significantly improved vertical seismic resolution after applying spectral inversion. The spectral inversion result for the marine seismic dataset (West of Shetland) showed increased seismic resolution and superior fault imaging compared to the conventional seismic data. Furthermore, seismic-to-well ties - including a blind well - very well support the realistic increase in vertical seismic resolution of the Kazakhstan seismic dataset. Finally, the evaluation of the onshore seismic dataset in Austria facilitated a new interpretation of the target sands which resulted in a revised geological model.

After careful evaluation of spectral inversion, OMV is convinced that this technology offers a valuable approach for better delineation and characterization of thin reservoirs and further projects will be performed.
Managing Risk through a Combination of Hazard Observation and Stop Work Authority Programs—Lessons Learned
Authors: Zerarka Said
Published: November 2012

An effective hazard observation program is essential for oil and gas organizations to manage risk and achieve superior health, safety and environment (HSE) performance. An effective hazard observation program is a core component of risk management in the workplace. Stop work authority (SWA) is an effective tool that enables and empowers employees to intervene and address clear and present dangers. Stop work authority promotes employee ownership in the workplace and helps to promote a successful hazard observation program. Supervisors play an essential role in the success of hazard observation and intervention programs by coaching employees in the identification of various hazards and supporting their interventions, as well as by recognizing these observations and completing a timely follow up of them.

Since Halliburton re-launched its SWA initiative in 2011, we have observed an increase in employee participation in hazard observations as well as better identification of these hazards. Furthermore, we noticed an increase in employee intervention to correct unsafe acts or unsafe conditions. Equally important, improvement was made in timely follow up and closing of these observations by supervisors.

This paper shares some best practices and successful case histories through the study and analysis of field data of a combination of hazard observations and SWAs in some of the operations locations where the service company is working in Algeria and the Sultanate of Oman.

This paper describes key success factors for the hazard observation program and demonstrates the positive impact of SWA on employee observations and interventions.
Improving Major Project Development Trough a Front End Loading Management System: Medco's way for Oil&Gas Development Project
Authors: Mishar Syahrilyan N.
Published: November 2012

As we enter the era of no more easy oil/gas, where reserves are located in remote areas with no nearby infrastructure available and multiple new stakeholders are involved, a complex E&P development project is something to be expected. To help the business process, a structured methodology is urgently needed to increase the predictability of a project outcome by reducing the risks from technical, commercial, legal, and other aspects in order to ensure the project is viable prior to authorization and to moving on to the next step.

The methodology which addresses this is commonly known as the Front End Loading (FEL) process, which uses a stage gate system for assurance. For smaller and newer E&P companies, this process is often underestimated, if not overlooked, unless the management realizes it is critical for business growth.

During the last three years, Medco has applied this FEL process to its major development projects as it begins to expand its capability in the E&P business. Several challenges have been faced during implementation of the FEL process and managed accordingly, including the different approach to loading a project to the process, and readiness for applying this new process and a new system.

All Medco E&P major development projects are now clearly mapped out, deliverables are well defined, risks are identified and mitigated through this stage gate system. Hence, projects are managed with the right level of attention and optimum number of resources. Through this FEL process, Medco aims to sustain or even increase the value of a project and return for a larger business growth potentials.

This presentation will report on findings and lessons learnt during Medco's early implementation of this FEL process for its major development projects.
Variations in Bounding and Scanning Relative Permeability Curves with Different Carbonate Rock Types
Authors: Dernaika M. R. , Basioni M. A. , Dawoud A. , Kalam M. Z. , Skjæveland S. M.
Published: November 2012

Relative permeability curves generally exhibit hysteresis between different saturation cycles. This hysteresis is mainly caused by wettability changes and fluid trapping. Different rock types may experience different hysteresis trends due to variations in pore geometry. Relative permeability curves may also be a function of the saturation height in the reservoir.

A detailed laboratory study was performed to investigate relative permeability behavior for a major carbonate hydrocarbon reservoir in the Middle East. Representative core samples covering five reservoir rock types (RRT) were selected based on whole core and plug X-ray CT, NMR T2, MICP, porosity, permeability and thin-section analyses. Primary drainage and imbibition water-oil relative permeability (bounding) curves were measured on all the five rock types by the steady state technique using live fluids at full reservoir conditions with in situ saturation monitoring. Imbibition relative permeability experiments were also conducted on the main RRT samples to assess the relative permeability (scanning) curves in the transition zone by varying connate water saturations.

Hysteresis effects were observed between primary drainage and imbibition cycles, and appeared to be influenced by the sample rock type involved (i.e. wettability and pore geometry). Variations in relative permeability within similar and different rock types were described and understood from local heterogeneities present in each individual sample. This was possible from dual energy CT scanning and high resolution imaging. Different imbibition trends from both oil and water phases were detected from the scanning curves which were explained by different pore level fluid flow scenarios. Relative permeability scanning curves to both oil and water phases increased with higher connate water. Relative permeability to oil was explained based on the occupancy of the oil phase at varying connate water saturations. The change in water relative permeability trend was addressed based on the connectivity of water at the varying connate water saturations. These results and interpretations introduced improved understanding of the hysteresis phenomena and fluid flow behavior in the transition zone of a cretaceous carbonate reservoir which can assist in the overall reservoir modeling and well planning.
Maximize the Ultimate Recovery by Designing and Optimising a CO2 Miscible Gas Injection Pilot in a Giant Carbonate Oil Reservoir, Abu Dhabi
Authors: Rawahi A. , Hafez H. H. , Al-Yafei A. , Al-Hammadi K. , Ghori S. G. , Putney K. L. , Matthews T. R. , Harb R.
Published: November 2012

It is critical to properly design a CO2 injection pilot for its successful implementation. A detailed pilot design provides valuable information in field development decisions especially when managing high CAPEX. This paper presents detailed workflow of a miscible CO2 gas injection pilot design for a giant onshore oil reservoir in Abu Dhabi, UAE. A technical feasibility study was performed in over a two year period by Abu Dhabi National Oil Company (ADNOC), ExxonMobil, and Abu Dhabi Company for Onshore Oil Operations (ADCO).

The key objectives of the study were to evaluate the CO2 EOR potential of the field, reduce performance uncertainty, and productively utilize a specific amount of CO2. A distinctive workflow was developed to identify the optimum pilot design that would successfully achieve these objectives.

The project started with a comprehensive screening process to select a candidate reservoir and a suitable pilot location within this reservoir. A high definition representative sector model was then used to design the pilot. First, pilot well concept parameters such as well pattern, type, and orientation were selected to maximize oil recovery. Second, key subsurface uncertainties and design parameters were identified that would have the greatest impact on pilot performance. The Experimental Design technique was then used to evaluate these uncertainties. Finally, a deterministic simulation model was used to predict the expected range of pilot performance.
CO2 EOR Scheduling by Analytical Model (CESAM)
Authors: Tanakov Mikhail , Al Yafei Arafat
Published: November 2012

This paper presents a new approach developed for high-level scoping analysis, forecasting and scheduling of CO2 EOR projects for multiple reservoirs and fields. The approach utilizes available reservoir simulation, analytical predictions and analog data on a full-field scale and approximates them with analytical functions. This allows for very fast forecasting of oil and CO2 production rates and determines the requirements for make-up CO2 under different potential development scenarios, including piloting phases. Built in MicrosoftTM Excel with VBA code and an advanced solver add-in, this scheduling tool enables the timely use of probabilistic Monte Carlo simulation for estimating the impact of uncertain input parameters on CO2 flood performance from multiple reservoirs. A numerical optimization algorithm searches for the best development schedule by optimizing the start-up times for a number of planned CO2 injection projects subject to allowable oil rate and CO2 supply constraints. Another optimization algorithm matches the estimated CO2 demand with supply from multiple natural and industrial sources and predicts the best time to commission CO2 capture facilities, thus maximizing CO2 utilization by EOR schemes rather than disposing it in depleted reservoirs or saline aquifers.
Comprehensive Diagnostic and Water Shut-off in Open and Cased Hole Carbonate Horizontal Wells
Authors: Ahmad Nawawi , Al-Shabibi Hussain , Zeybek Murat , Malik Shauket
Published: November 2012

Increases in water production can significantly reduce well performance and life of a well, and cause decreased oil production. Water influx can occur through several mechanisms and approach from several directions; accurate diagnostic information is important for the design of successful shutoffs and effective results. To mitigate this situation, water management is crucial. One option is to isolate the water producing zone with a rigless water shut-off technique, which is less costly than the use of workover rigs for interventions.

This paper presents case histories of five horizontal wells drilled in carbonate formations and producing excess water; three were completed in open hole and two were cased. A multiphase production logging (MPL) tool equipped with five miniaturized spinners for phase velocity measurement and six electrical and six optical probes for holdup data provided important diagnostic data for the decisions on remedial actions. Using the tool data, the operator pinpointed the water entries and performed shutoff operations based on the source of the entries and water flow profiles. Subsequent production test results showed that the water cut was reduced in all the wells. Examples from open and cased hole completions are shown utilizing a number of different shutoff techniques. In addition, oil production was considerably increased in many of the wells. These results demonstrate that accurate diagnostic information and an integrated approach are keys to successful rigless water shutoffs.