bluuebunny/crossref_metadata_2025_split huggingface dataset:
Shake and Go - Advances in Vibroseis Technology
Authors: Krohn Christine Elizabeth , Neelamani Ramesh , Johnson Marvin 
Published: February 2016

Abstract
A new patented vibroseis acquisition method, Shake and GoSM, allows operation of multiple vibrators at multiple source points simultaneously and continuously with no waiting for between-sweep listening times or for between-vibrator slip times. This method allows for unsurpassed production rates. Model simulations, field gathers, and processed stacks are used to demonstrate excellent data quality compared to other high productivity methods.
The cost of vibroseis land acquisition is directly related to the time it takes to shake each vibrator point and move to the next point. Shake and Go can be used to record seismic data at lower cost, or it can be used to record more data at the same cost with improved sampling of signal and noise. It is especially efficient for new point source and point receiver (MEM) acquisition without arrays.
Shake and Go, also called C-HFVSSM or Continuous High Fidelity Vibrator SeismicSM, uses long segmented sweeps and HFVS separation. Measurements of the individual vibrator motion are recorded and used to derive a filter that optimally recovers individual seismograms from vibrators operating simultaneously. Cross contamination from strong events, which are simultaneously recorded, are not observable in the individual recovered seismograms. Interference and harmonic noise from the continuous sweeping are limited to the end of a long record and can be removed with a new novel processing method.
Because of the high production rates and high data quality, the new method is expected to dominate land acquisition in the future. We present analysis of the noise and show data comparisons for different vibroseis methods. We also overcome the limitation that there must be as many sweeps as vibrators or time delays to optimally separate records for simultaneous sourcing.

Methodology
Shake and Go or Continuous-HFVSSM (C-HFVSSM) is a combination of ExxonMobil's HFVS (High Fidelity Vibratory Seismic) method and its proprietary Cascaded-Sweep technique. Both acquisition methods, HFVS and its super high efficiency version C-HFVS are licensed to a number of contractors. We have recently developed a proprietary processing method (patent application filed) to further improve the quality of the C-HFVS method so that it matches the high quality of HFVS and allows us to exploit super high efficiency acquisition without any compromise in data quality.
KOC 1% Gas Flaring Target
Authors: Al-Otaibi Faisal , Al Adwani Adnan Eid , Nour Maher Mustafa 
Published: February 2016

Abstract
Gas flaring is increasingly recognized as a major environmental problem, contributing more than 1% to global emissions of CO2 in addition to its valuable resource. At KOC an effective utilization of associated gas in all fields became a serious concern in 1995 and ongoing efforts were put in place for minimizing gas flaring. Detailed exercises were carried out in 1996/1999 for identifying causes, establishing action plans, and setting allowable targets. Current Action Plan covers the following on-going activities:Operating Process & ProceduresTraining & DevelopmentFlaring Awareness ProgramGas Supply TeamIn-hand Projects
All the above-mentioned planned implementations are on schedule and are expected to be completed by 2010/2011 in order to reach the target of 1% gas flaring at KOC.

INTRODUCTION
Crude oil contains associated hydrocarbon gases and when brought to the surface the gases are released and where there is no market for the gas, the industry standard for disposal is flaring (1). Flaring of produced gas is the process of burning-off surplus combustible vapors from a well, either as a means of disposal or as a safety measure to relieve well pressure and it is the most significant source of air emissions from onshore and offshore oil and gas installations. Venting also occurs - releasing un-burnt gases directly into the atmosphere and alternatives include re-injection, on-site power generation, and transport to market (1). The following are the Four Main Causes of Gas Flaring:Culture: gas was once viewed as a waste product, global warming was not an issue.Contracts: flaring permitted and there was no obligation to find a market for the gas.Markets: markets poorly developed and responsibilities for marketing ill-defined.Governance: no incentive to maximize economic use of gas.
According to the Alberta Energy and Utilities Board (AEUB), there are four main reasons for flaring:As a part of the completion and testing of natural gas wells.During routine maintenance at gas compressing facilities.When oil wells produce very small amounts of solution gas.In emergency situations when there is an uncontrolled release of gas from a well or pipeline.

AMOUNTS AND EFFECTS OF GAS FLARING
World Bank estimates that over 150 bcm of gas is flared annually (2) and this is equivalent to the combined annual gas consumption of Germany and France. This amount of gas flared is also equivalent to 25% of US consumption. Reference to the figure below, the 40 bcm of gas flared in Africa is equivalent to half of the continent's power consumption.
Pattern Balancing and Waterflood Optimization of a Super Giant: Sabiriyah Field, North Kuwait, a Case Study
Authors: Clark Robert Alfred , Karami Hossein , Al-Ajmi Moudi Fahad , Lantz James R. 
Published: February 2016

Abstract
This paper outlines the successful integration of subsurface, water handling, well surveillance and production operations teams across the North Kuwait asset to significantly improve the operating procedure for waterflooding the Sabiriyah Mauddud field. This effort required a new way of managing this reservoir in NK: a multifaceted approach of balancing voidage with injection, conducting extensive surveillance/analysis within the reservoir to assess the efficacy of various courses of action and, most significantly, adjusting various teams' "key performance indicators" (KPIs) to align injection and production allowables with sound reservoir management principles.
An innovative, unified information management system was used to monitor voidage replacement ratio (VRR) to provide a basis for pattern balancing. Extensive surveillance operations provides the data necessary to monitor individual pattern balance, watercut performance, optimize areal sweep efficiency by adjusting injection and production allowables, assist in planning water shutoff operations, and design new completions.
Waterflooding the Cretaceous Mauddud reservoir is in an early stage of operations. Water injection commenced in 12 of 17 predrilled waterflood patterns in 2000. These wells were drilled on an inverted nine-spot pattern with spacing of 250 acres per well to quickly provide coverage over the major portion of the reservoir. Surveillance data indicates the reservoir is relatively well connected. Pattern VRR, pressures, and watercuts were somewhat out of balance prior to engaging in this effort. Now, individual waterflood pattern balance is significantly improved and the field-wide VRR is ~1.
Sound reservoir surveillance and waterflood management procedures implemented within a diverse group of teams that have performance goals aligned with "best practice" has resulted in effectively re-balancing this major waterflood. This effective integration of teams retains the flexibility to adjust for an ongoing development of this super giant field.

The Sabiriyah Field
The Sabiriyah field was discovered in the 1950's with the drilling of the SA-001 well. Production commenced in 1958. Located in North Kuwait (Figure 1), Sabiriyah Field consists of several stacked pay intervals, trapped in a North-South elongated faulted anticline with approximately 500 ft. of present-day four-way closure (Figure 2). Present-day closure has been modified slightly by a recent structural tilt, which occurred after the trap was filled with oil. To date, the major oil pay intervals in the Sabiriyah field occur between 7,100–8,300 ft. drilling depth and include various high-productivity Burgan sandstones overlain by a more moderate-permeability shallow-water ramp-carbonate, the Mauddud. These reservoirs were normally- pressured at the time of discovery.
The Role of Seismic Coherence Attributes in Mapping the Fracture Network and Improving the Productivity From Thick, Tight and Fractured Deep Gas Reservoir
Authors: Qassim Naji A. , Al-Anaisi Abdulla Jaffar , Al-Muftah Ali Ebrahim 
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.
This paper describes an integrated study of utilizing 3D seismic, open hole logs with simulation, pressure transient analysis and production data to define and map fracture network patterns to aid enhance the productivity from thick, tight and fractured deep gas-bearing carbonate reservoir in the Bahrain field. The Lower Permian K3 zone is a thick, tight, highly faulted and irregularly fractured Carbonate reservoir. The massive 800 ft thick reservoir with very low average permeability of the order of 1 md, poses challenge in efficient recovery of hydrocarbons. The present production from this thick reservoir accounts for less than 10 % of the total gas production from the Khuff Formation of the field. This has prompted a detailed integrated study to help enhance the well productivity. It is well known that seismic coherence data plays a pivotal role in defining and mapping fracture network and similarly well testing to understand the reservoir dynamics and connectivity. The approach involves identification of fracture network from seismic data and validating them with transient well testing & production data at and around well-bore. The study is applied to derive and input fracture network and related data of the K3 zone into the simulation model to define and map the reservoir fracture patterns to aid in increasing productivity and also recovery.
Optimized EOR Design for the EWE area, Greater Prudhoe Bay
Authors: Panda Manmath Nath , McGuire Patrick Lee , Ambrose James Gilbert , Beuhler Gilbert G. 
Published: February 2016

Abstract
The Prudhoe Bay field, located on the north coast of Alaska, is the largest oil field in North America. Discovered in 1968, the Prudhoe Bay field is a massive sandstone reservoir complex covering over 200 square miles.
Eileen West End (EWE) is a western extension of Prudhoe Bay field, connected only through the aquifer. It consists of two tilted fault blocks, each with a gas cap and an oil leg having a combined OOIP over 750 MMSTB. Production began at EWE in June, 1988, approximately 11 years after Prudhoe field startup.
Initially, EWE was considered an analogue to the gravity drainage area of Prudhoe Bay. The reservoir management strategy employed at EWE was gas cap expansion and gravity drainage of oil with injection of Prudhoe Bay produced gas into the EWE gas caps. A review of surveillance data, material balance studies, fluid mapping, simulation and other analogue data, changed the perception that gravity drainage was an efficient recovery process at EWE. The work also showed that aquifer influx was stronger than anticipated. As a result, gas injection was stopped in 2001 and water injection into the gas caps was started for pressure maintenance and to prevent oil from resaturating the gas cap.
A pattern water alternating miscible gas (WAG) flood was initiated in 2003. The initial WAG patterns targeted areas with large gas cap expansion and gas underruns to capture oil trapped in these gas invaded intervals. The WAG flooding is being expanded to areas of low gas cap expansion and peripheral regions.
This paper describes the technical process used to select the major design parameters of the pattern WAG flood to optimize EWE recovery. The key parameters evaluated were slug size, injection rate, WAG ratio, and WAG sequencing. A fine grid fully compositional numerical simulator was used to determine the optimal design parameters. The modeling indicated that optimal design consists of multiple WAG cycles with high voidage replacement ratio (VRR) during the gas cycle with an overall WAG ratio of 1. Timing of the first gas slug within the first year after start of waterflood in addition to realignment of the injection and production wells also optimizes recovery. Surveillance of the secondary and tertiary recovery through well performance monitoring and surface and down hole data acquisition combined with classical reservoir engineering is ongoing to ensure that the EWE enhanced oil recovery (EOR) project remains optimized.
Application of Six Sigma Statistical Methodology to Reduce ESP Failures in Central Arabia Fields
Authors: Al-Hamdan Mohammed Radhi 
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.
This paper presents the application of Six Sigma statistical methodologies to diagnose, measure, improve, and control the root causes of electrical submersible pump (ESP) failures in Central Arabian (CA) fields. The word six sigma is a statistical term that measures how far a given process deviates from perfection. The main objective of this study is to increase the run life of ESPs in six Central Arabian fields of Saudi Arabia to at least three years or more using Six Sigma tool. In the last ten years 241 ESPs have experienced downhole equipment failure and were subsequently replaced at Central Arabia fields. This has a huge impact on over all fields' performance and economic resources which would be utilized elsewhere otherwise. This study was initiated and focused to diagnose the major causes of 23 ESP failures occurred in the year 2005 only. However, the scope of work will be extended to the previous failures as well. It was found that 22% of the total failures were caused by sand accumulation inside the pump stages. Scale, downthrust, and seal problems caused 51% failures with 17% each. Underestimated water cut forecasts in successive years and poor installation practices were responsible for 18% failures with 9% each. Lastly, upthrust and cable problems together caused 8% ESP failures with 4% each. This paper is divided into four sections: Effective data collection methodologies are outlined,ESP run life analysis is discussed in detail,findings and root causes of ESP failures are listed,finally, based on the findings, solutions and quality control procedures are recommended.
Some of these solutions and procedures have been implemented since March 2006 and have resulted in significant reduction in the number of premature ESP failures as compared to the previous year.
Modeling Uncertainties of a Gas-Delivery Project
Authors: Frizzell Dominique F. , Sibley Michael , Cotner Bryan Clayton , McCartney Simon Peter , Schmidt George Russell , Burkes Robert , Phelps James , Tosdevin Michael Andrew , Mazloom Jalal 
Published: February 2016

Abstract
A primary objective of any project evaluation is to understand the fundamental economic value and the uncertainty in that value. The uncertainty in value is a function of numerous variables in both the surface and subsurface parts of a project which are often evaluated separately. In fact, the surface and subsurface are tightly linked and should be studied together to fully quantify the effects of one on the other and on the economic value.
An evaluation was performed of more than 21 undeveloped fields with multiple reservoirs each to predict the economics of delivering gas at a nearly constant rate to a specific downstream project, and the associated oil and condensate to a country's export system. The fields are spread across a 6000 km2 area. The data comes from nearly 70 wells drilled mostly in the early 60's to a few today. The uncertainties associated with the reservoirs: gas in place, drive mechanism, inflow performance, fluid properties; were linked to the wells: well architecture, tubing flow performance, well head pressure; and linked to the pipelines: distance, diameter, liquid holdup, and elevation changes. All uncertainties were studied over their probable range of values.
This paper describes the application of mature technologies across the broad spectrum of disciplines required in most projects. The significance is the integration of the contributions from many experts into a model which gives a quantitative result of the impact uncertainties have in a linked surface / subsurface system, and their importance to the value of the project. The models used to describe the linked systems are commercially available software; the value of this paper is the description of the methodology used to evaluate and integrate many surface and subsurface uncertainties. Table 1 summarizes the uncertainties to be discussed.
Table 1: Summary of Uncertainties
Introduction
Understanding and quantifying uncertainty in major projects in the oil industry is not a new problem. Linking surface demands and performance to subsurface performance is a recognized need as well. References 1 to 4 at the end of this paper provide some more discussion and alternate approaches to the issues to be discussed here. The Influence Diagram below illustrates the interrelationships among surface and subsurface unknowns and begins to show why the two cannot be evaluated separately. The circles indicate inputs to calculations of performance; the boxes are decisions to be made. The inputs have some degree of uncertainty which is captured by a range of values for each.
Prevent system hydrate formation during sudden depressurization
Authors: Zeydabadi Babak Asadi , Haghshenas Mehri , Roshani Shahram , Moshfeghian Mahmood 
Published: February 2016

Abstract
A concise and accurate methodology has been developed using well known software packages to predict the type and amount of inhibitor required during sudden depressurization of a system to prevent hydrate formation. The outlined procedure exhibits the P-T history of the system and hence the hydrate formation temperature profile. A practical example of using such procedure clearly indicates the ease and accuracy of designing a hydrate inhibition package for any units in the oil, gas and petrochemical industries.

1. Introduction
A hydrate is a physical combination of water (H2O) and other small molecules producing a solid, which has an "ice-like" appearance but possesses a different molecular structure. Formation in gas and/or natural gas liquid (NGL) systems can plug pipelines, equipment, and instruments, and restrict or interrupt flows. There are three crystalline structures for such hydrates. In each, H2O molecules - host molecules - build the lattice, and hydrocarbons, nitrogen (N2), xenon (Xe), argon (Ar), carbon dioxide (CO2) and hydrogen sulfide (H2S) - guest molecules - occupy the cavities. Smaller molecules such as methane (CH4), ethane (C2H6), CO2, and H2S stabilize a body-centered cubic called Structure I. Larger molecules propane (C3H8), isobutene (iso-C4H10) and n-butane (n-C4H10) form a diamond-lattice called Structure II. Molecules larger than n-C4H10 do not form hydrates as they are too large to stabilize the lattice.1
Gas composition determines structure type and mixed gases will typically form Structure II lattices. Limiting hydrate numbers (the ratio of H2O molecules to molecules of included gaseous component) are calculated using gas molecule sizes and cavity sizes in a H2O lattice. The structure type does not affect appearance, properties or problems caused by the hydrate; it does, however, have a significant effect on the pressure and temperature at which hydrates form. Also Structure II hydrates are more stable than Structure I. Structure H hydrates are a double hydrate that requires two kinds of molecules to be stabilized: a small molecule like Xe, Ar or H2S and a larger molecule like methylcyclohexane.2,3
Natural gas mixtures that have H2S present result in a substantially warmer hydrate formation temperature at a given pressure. CO2, in general, has a much smaller impact and often reduces the hydrate formation temperature at fixed pressure for a hydrocarbon gas mixture.4,5
Using Down-Hole Control Valves to Sustain Oil Production from the First Maximum Reservoir Contact, Multilateral and Smart Well in Ghawar Field: Case Study
Authors: Al-Mubarak Saeed Mohammed , Pham Tony Reuben , Shamrani Sultan S. , Shafiq Muhammad 
Published: February 2016

Abstract
This paper describes a case-study detailing planning, completion, testing, and production of the first Maximum Reservoir Contact (MRC), Multilateral (ML) and Smart Completion (SC) deployment in Ghawar Field.
The well was drilled and completed as a proof of concept. It was completed as a trilateral and was equipped with a SC that encompasses surface remotely controlled hydraulic tubing retrievable advanced system coupled with pressure and temperature monitoring system.
The SC provides isolation and down hole control of commingled production from the laterals. Using the variable positions flow control valve, the well was managed to improve and sustain oil production by eliminating water production. Monitoring the rate and the flowing pressure in real time allowed producing the well optimally.
The appraisal and acceptance loop of the completion has been closed by having this well completed, put on production and tested. Approval of the concept was achieved when the anticipated benefits were realized by monitoring the actual performance of the well.
Leveraged knowledge from this pilot has provided an insight into SC capabilities and implementation. Moreover, it has set the stage for other developments within Saudi Aramco.

Background
Haradh forms the southwest part of the Ghawar oil field located about 80 kms onshore from the Arabian Gulf, in the Eastern Province of Saudi Arabia (Figure-1). Haradh field consists of three increments where the initial production started in May, 1996 from Increment-1 followed by Increment-2 and 3 in April, 2003 and January, 2006, respectively.
Increment-1 was initially developed using mainly vertical wells while Increment-2 was developed with horizontal wells. The subsequent MRC, ML wells and Smart Completion installations in Increment-2 were part of a proof of concept project to test and evaluate the impact of these technologies on reservoir, well performance and overall reservoir management strategies. As a result of the proof of concept project, Increment-3 was developed with MRC, ML wells with SCs.