bluuebunny/crossref_metadata_2025 huggingface dataset:
Cladid crinoids from the Late Kinderhookian Meadville Shale, Cuyahoga Formation of Ohio
Authors: Kammer Thomas W. , Roeser Edgar W.
Published: May 2012

A total of 17 species of cladid crinoids are documented from the late Kinderhookian Meadville Shale Member of the Cuyahoga Formation of northeastern Ohio, the most diverse assemblage of Kinderhookian-age cladids known in North America. One new genus, six new species, and seven new combinations are reported. New taxa includeCuyahogacrinus lodiensisnew genus and species, and the new speciesCyathocrinites simplex, Atelestocrinus meszarosi, Goniocrinus sceletus, Aphelecrinus gracilis, andLebetocrinus ohioensis.New combinations includeLogocrinus warreni(Laudon et al., 1952),Histocrinus aegina(Hall, 1863),Paracosmetocrinus richfieldensis(Worthen, 1882),P. corycia(Hall, 1863),Acylocrinus lyriope(Hall, 1863),Linocrinus merope(Hall, 1863), andL. paternus(Hall, 1863). Remaining taxa includeCyathocrinites lamellosus(White, 1863) andAscetocrinus whitei(Hall, 1861), both of which also occur in the Osagean Burlington Limestone, and the endemic speciesCosmetocrinus crineus(Hall, 1863) andPachylocrinus subtortuosus(Hall, 1863).

Collectively, the cosmopolitan genera and species of cladids show a greater overall affinity with Osagean cladid faunas than with other Kinderhookian cladid faunas. However, this is true for other Kinderhookian cladid faunas as well that individually have more taxa in common with Osagean faunas than other Kinderhookian faunas. This suggests a greater degree of endemism and local speciation during the Kinderhookian as a prelude to the rapid radiation of cladids, and other crinoids, during the Osagean.
Hierarchical distance‐sampling models to estimate population size and habitat‐specific abundance of an island endemic
Authors: Sillett T. Scott , Chandler Richard B. , Royle J. Andrew , Kéry Marc , Morrison Scott A.
Published: May 2012

Population size and habitat‐specific abundance estimates are essential for conservation management. A major impediment to obtaining such estimates is that few statistical models are able to simultaneously account for both spatial variation in abundance and heterogeneity in detection probability, and still be amenable to large‐scale applications. The hierarchical distance‐sampling model of J. A. Royle, D. K. Dawson, and S. Bates provides a practical solution. Here, we extend this model to estimate habitat‐specific abundance and rangewide population size of a bird species of management concern, the Island Scrub‐Jay (Aphelocoma insularis), which occurs solely on Santa Cruz Island, California, USA. We surveyed 307 randomly selected, 300 m diameter, point locations throughout the 250‐km2island during October 2008 and April 2009. Population size was estimated to be 2267 (95% CI 1613–3007) and 1705 (1212–2369) during the fall and spring respectively, considerably lower than a previously published but statistically problematic estimate of 12 500. This large discrepancy emphasizes the importance of proper survey design and analysis for obtaining reliable information for management decisions. Jays were most abundant in low‐elevation chaparral habitat; the detection function depended primarily on the percent cover of chaparral and forest within count circles. Vegetation change on the island has been dramatic in recent decades, due to release from herbivory following the eradication of feral sheep (Ovis aries) from the majority of the island in the mid‐1980s. We applied best‐fit fall and spring models of habitat‐specific jay abundance to a vegetation map from 1985, and estimated the population size ofA. insulariswas 1400–1500 at that time. The 20–30% increase in the jay population suggests that the species has benefited from the recovery of native vegetation since sheep removal. Nevertheless, this jay's tiny range and small population size make it vulnerable to natural disasters and to habitat alteration related to climate change. Our results demonstrate that hierarchical distance‐sampling models hold promise for estimating population size and spatial density variation at large scales. Our statistical methods have been incorporated into the R packageunmarkedto facilitate their use by animal ecologists, and we provide annotated code in the Supplement.
Pest control experiments show benefits of complexity at landscape and local scales
Authors: Chaplin-Kramer Rebecca , Kremen Claire
Published: May 2012

Farms benefit from pest control services provided by nature, but management of these services requires an understanding of how habitat complexity within and around the farm impacts the relationship between agricultural pests and their enemies. Using cage experiments, this study measures the effect of habitat complexity across scales on pest suppression of the cabbage aphid Brevicoryne brassicae in broccoli. Our results reveal that proportional reduction of pest density increases with complexity both at the landscape scale (measured by natural habitat cover in the 1 km around the farm) and at the local scale (plant diversity). While high local complexity can compensate for low complexity at landscape scales and vice versa, a delay in natural enemy arrival to locally complex sites in simple landscapes may compromise the enemies' ability to provide adequate control. Local complexity in simplified landscapes may only provide adequate top‐down pest control in cooler microclimates with relatively low aphid colonization rates. Even so, strong natural enemy function can be overwhelmed by high rates of pest reproduction or colonization from nearby source habitat.
Asynchronous changes in phenology of migrating Broad‐tailed Hummingbirds and their early‐season nectar resources
Authors: McKinney Amy M. , CaraDonna Paul J. , Inouye David W. , Barr Billy , Bertelsen C. David , Waser Nickolas M.
Published: May 2012

Phenological advancements driven by climate change are especially pronounced at higher latitudes, so that migrants from lower latitudes may increasingly arrive at breeding grounds after the appearance of seasonal resources. To explore this possibility, we compared dates of first arrival of Broad‐tailed Hummingbirds (Selasphorus platycercus) to dates of flowering of plants they visit for nectar. Near the southern limit of the breeding range, neither hummingbird arrival nor first flowering dates have changed significantly over the past few decades. At a nearby migration stopover site, first flowering of a major food plant has advanced, but peak flowering has not. Near the northern limit of the breeding range, first and peak flowering of early‐season food plants have shifted to earlier dates, resulting in a shorter interval between appearance of first hummingbirds and first flowers. If phenological shifts continue at current rates, hummingbirds will eventually arrive at northern breeding grounds after flowering begins, which could reduce their nesting success. These results support the prediction that migratory species may experience the greatest phenological mismatches at the poleward limits of their migration. A novel hypothesis based on these results posits that the poleward limit for some species may contract toward lower latitudes under continued warming.
Targeting Catastrophic Thinking to Promote Return to Work in Individuals With Fibromyalgia
Authors: Sullivan Michael J. L. , Adams Heather , Ellis Tamra
Published: May 2012

In this study, a sample of 30 individuals with fibromyalgia (FM) were enrolled in a 10-week risk factor targeted intervention designed to promote return to work. Participants completed measures of pain severity, pain catastrophizing, fear of movement, depression, and self-reported disability at three points in time through the course of the intervention. Results showed that most individuals with FM were agreeable to participate in the return-to-work intervention. Treatment response of individuals with FM was compared to a matched sample of individuals with chronic low back pain (CLBP). Analysis of variance (ANOVA) revealed that both groups showed comparable reductions in pain catastrophizing, depression, and fear of movement through the course of treatment. Individuals with FM were less likely than individuals with CLBP to show clinically meaningful reductions in pain severity and self-reported disability. Patients with FM were less likely to return to work (23%) than participants with CLBP (50%). The findings suggest that although individuals with FM are more treatment resistant than individuals with CLBP, a significant proportion can still benefit from participation in a rehabilitation intervention with a stated objective of return to work. Implications of the findings for the structure and content of rehabilitation interventions for FM are discussed.
Success Story: Importance of Reservoir Monitoring For Finding Bypassed Oil Which Lead Production Incremental 295%
Authors: Khresno Sri , Suderajat Suderajat , Prakoso Ambaria , Kurniawan Akbar , Nur Ilhami , Ontowiryo Bambang
Published: May 2012

The Lower Sihapas Formation in the M-Field consists of sandstones with subordinate inter-beds of mudstones, shale and coals.

The C sand is a Darcy-permeability blocky sand and part of Lower Sihapas Formation. In the M2-03 well, in 1987, the C sand was perforated at the top of sand to drain oil from the entire sand. After 24 years of production, when the oil rate was 16 BOPD and the water cut was 99%, we ran through-tubing C/O log to look for by-passed oil in any sand. The RST result shows unswept oil in C sand. Other supporting data are also bringing into upswept potential are: Production log data shows small flow contribution from C sand, suggesting small cumulative production; Micro Resistivity Image logs from offset wells suggested the C sand is might be laminated sand that could impacts on low productivity, and also may isolate existing perforation from lower sand body ofthe sand.

The attractive water saturation in the lower sand of 40% from the C/O log might be right.So, we decided to perforate the lower C sand using a through-tubing gun. After perforation, the oil rate spiked at 2000 BOPD and then quickly settled down to 100 BOPD. The cost for the C/O log and perforation was recovered within days. Executing a through-tubing perforation instead of a "stronger" casing gun perforation via a workover saved us more than $250,000.

This data has enabled us to act to slow production decline, save wellwork cost and extend the economic life of platforms. We continue to find that cased-hole logging with Production log and C/O log adds value in mature high water-cut oil wells, by identifying watered out sands and by-passed oil sands.
Balancing Project Schedule & Cost on Sour Gas Development Project Case Study
Authors: Asmoro Trian Hendro , Putri Autie Minati
Published: May 2012

The gas field development project is a challenging phase, since wells need to be drilled to assess the oil/gas reserves and production facilities need to be built. The ultimate objective of the project is to deliver the gas sales to selected buyers as per agreed schedule and price. As result, the project schedule and cost are defined to achieve the objective.

Project schedule and cost are known to work in equilibrium. Where one of these dimensions is restricted or extended, the other dimension will then also need to be either extended/increased or restricted/reduced in some way. Given that quality must not be compromised, this paper aims to describe how to get the optimum balance of project schedule and cost on an onshore gas processing plant project located in north-east Indonesia with 90 MMSCFD feed gas capacity. The feed gas has a high content of CO2 and H2S.

The schedule of the development project was initially divided into 2 phases: Early Production using sweet gas facilities will be constructed in 22 months and Complete Phase 1 with sour gas facilities will be constructed in 26 months. The project cost was developed by referring to third party cost estimates as part of FEED, to the most recent quotation from the vendor, and to the project cost owner. The Government had to approve the CAPEX of the project as part of the PSC scheme.

Monte Carlo simulation was used to calculate risks related to schedule and cost estimates and furthermore to establish realistic ones. The simulation showed that p75 falls within 28 months and MUSD 200 for project phase-1 completion. However, according to its commitment to the gas buyer, the company has to deliver gas within a maximum period of 22 months, which makes this project very challenging.
Using Bayesian Network to Model Drilling Fluids Practices in Saudi Arabia
Authors: Al-Yami Abdullah S. , Schubert Jerome
Published: May 2012

Texas A&M University recently has established a new method to develop a drilling expert system that can be used as a training tool for young engineers or as a consultation system in various drilling engineering concepts such as drilling and completion fluids, cementing, completion, and underbalanced drilling practices. To the best of the authors knowledge there is no standards developed to aid drilling engineers and scientists to formulate effective drilling fluids systems for the entire well sections.

The objective of this paper is to set a module that should aid drilling engineers when designing drilling fluids. A module was created based on several inputs. To create this module, we interviewed experts to gather the information required to determine best practices as a function of different probabilities. Drilling fluids formulations were gathered from Saudi Arabia fields to build up this model.

The Bayesian approach was found suitable for designing expert system. The model can work as a guide to aid drilling engineers and scientists to design and execute optimum drilling fluids. Using this approach to build up expert systems is more flexible than using flow charts. Updating flow charts is time consuming and require redesigning them again to be used by different experts or in different fields. Using Bayesian network allows us to update our industry practices by updating the probabilities states mentioned in this paper.
Appraising the Performance of Cyclic Production Scheme through Reservoir Simulation, a Case Study
Authors: AI-Zahrani Tariq
Published: May 2012

Oil wells in mature fields with strong aquifer influx and the first row of producers near peripheral water injectors experience very high water cuts (above 80%), which cause lower oil production and increasing disposal costs.

To mitigate this situation, various production strategies have been implemented in this simulation study to reduce water production, optimize oil production and revive dead wells. One strategy is to implement a cyclic production scheme (CPS). The CPS requires alternate shutting and flowing of wells with high water cuts over predetermined time cycles. The main objectives of the cyclic strategy is to reduce water production by optimizing oil production, minimizing coning effect and having a better control of the uniform waterflood front to the up-dip producers. This strategy enhances the sweep efficiency, improving pressure maintenance and minimizing water production.

This simulation study assesses the effectiveness and the performance of CPS implemented in a reservoir simulation model of a mature oil field. Simulation runs with several scenarios were conducted to understand and optimize the impact of CPS. The simulation results provided the best cyclic production/shut-in period and showed significant advantages of applying CPS over the regular noncyclic production in all scenarios. In this study, more than 93 wells have been evaluated and most of these wells showed good overall oil recovery after applying the CPS strategy.
Solving the Complex Equation of Production Build-up via the Implementation of Integrating Processes: A Team Approach Pilot to Meet North Kuwait's Production Target
Authors: Chetri Hom B. , Al-Ajmi Hussain
Published: May 2012

Production has two components – the subsurface potential and the actual production to feed the export line. In North Kuwait, sub surface potential had never been an issue for any speculation. The most difficult part is to integrate all resources, synchronize with each other and create "wonderful symphony" leading to actual production delivery. Several processes have been developed and matured now to gear up the asset to meet the challenging production target for 2010–11 which indicates a jump in production by about 23% in a single year.

In this effort, major processes to play a key role are: Development Well Subsurface Selection Process to optimize the best wells in terms of potential; New Development Well Assurance Process with Key Opportunities for Improving integration with key service providers to NK Asset such as Drilling Group (rig schedule, materials); Production Operations (Flow line/header connections, process capacity); Water Handling (Flow line/header connections, Water injection Supply capacity); Artificial Lift to synchronize ESP equipment availability in line with the well/ rig availability, Project Management (Flow line installation & rationalization), Learning's from Post Appraisal of Wells drilled in last few years; Surveillance Plan - data acquisition, how new information helps to minimize reservoir uncertainties; Drilling & Completion Programs - appropriate technology choices to meet well and reservoir objectives such as multi-zone needs, rigless access for surveillance or interventions, NCWs and artificial lift requirements.
Novel Applications of Distributed Temperature Measurements to Estimate Zonal Flow Rate and Pressure in Offshore Gas Wells
Authors: Azim Reda Rabiee
Published: May 2012

Distributed Temperature Sensor (DTS) technology has recently developed to determine the zonal flow rate in gas/oil producing wells using the measured continuous temperature profile along the wellbore. Comapred to convenetial production logging tool (PLT), DTS has many advantages that can provide real time temperature data without any intervention.

Temperature logging applications described in early researches included, location of gas entries, detection of casing leaks and fluid movement behind casing, location of lost – circulation zones, and evaluation of cement placement.

Temperature logs are still used for these applications and others, but the most common use now is quanitative identification of injection or production zones. Despite the many other logs that have been developed, the temperature log remains the workhorse of the production logging stable. This is primarily because of its reliability; no matter what the wellbore flow conditions, temperature can be measured accurately, also the temperature logs tends to reflect the long term behavior of well, not just the current conditions.

This paper presents a new methodology developed to allocate gas rate and associated water of each individual layer using (DTS) and the total surface production of gas and water, also the pressure along the wellbore. The physics behind this model is based on steady-state gas-water flow in the wellbore, friction loss and Joule-Thomson effect in the wellbore, contrast in the thermal and physical properties of gas and water, wellbore heat losses due to unsteady heat conduction in the earth, and the mixing of the fluid streams of contrasting temperature.

The methodology allows users to run in two modes: forward simulation and flow profiling. The forward simulation mode calculates the temperature inside the wellbore at all producing layers at any given production profile to calibrate the model inputs. The flow profiling is used to estimate the production rate based on the measured temperatures using inversion technique. The implementation of the developed production allocation model is shown, in details, by using the data of two actual cases studies form Egyption offshore gaswells.
Electric Properties and Its Effect on Microporosity Rocks
Authors: Sbiga Hassan
Published: May 2012

This study has been undertaken in three oil fields (A-Libya, B-Libya, and C-Libya) in sirte basin located in Libya. Nubian sandstone Formation is the main reservoir in the studied oil fields. Laboratory measurements methods were applied on the core samples that were selected from three different fields of Nubian Sandstone. Some of these measurements were conducted in Libyan Petroleum Institute (LPI Tripoli-Libya) laboratories in order to determine the resistivity parameters of the central graben reservoir cores and to investigate the effect of rock hetrogeneity and wettability on the resistivity parameters of Nubian sandstone reservoir rocks. The pore size distribution was estimated from generated capillary pressure curves. The samples belonged to Nubian sandstone, Sirt basin were selected to perform formation resistivity factor measurements.

The Pore size distribution and type of pores were calculated from mercury injection capillary pressure data. The results indicated that changes had been observed in formation resistivity factor and cementation exponent when overburden pressure was applied (slightly increases in cementation exponent with increasing O.B.P).Wettability played an important role in determining the fluid movement, distribution and electrical conduction during desaturation processes. Resistivity index effect has been observed after wettability measurement showing oil-wet tendency.

From the results obtained, a good relation between resistivity and type of pores (macro and micro pore system) was observed. When oil begins to penetrate micro-pore systems during the measurements, a significant change in slope of the resistivity index relationship occurs.
Productivity Index Change as a Result of Reservoir Compressibility
Authors: Anisimov Leonid
Published: May 2012

Variability in formation pressure during drilling, well tests, injection operations, oil and gas recovery are accompanied by changes in rock permeability and consequent changes in well productivity, oil recovery factor, and land subsidence. A number of laboratory experiments have demonstrated that decreasing the rock permeability may be defined as relative permeability in connection with fluid replacement in rocks. Other experiments have demonstrated the same results by increasing grain-to-grain stress for the clastic rocks and fracture closing for the fractured carbonate reservoirs. Assessment of these factors can be based on the relationship between well production and well bore pressure drop, and this interaction can be demonstrated by the results of test operations and production history. In order to segregate these processes, it is necessary to study a reservoir and fluids as an inclusive system. The rate of compaction in the different parts of a reservoir depends on hydrocarbon extraction and maintenance of reservoir pressure that can be changed through injection of water or gas. Phase transition in the fluid system can also depend on formation pressure. Reservoir compaction provides the additional drive energy for production, whereas decrease in permeability deteriorates the condition of field development. These effects can be considered for both low and high permeability reservoirs.
Precision for Bigger Diameters: The World's First 4 Tube Coriolis Mass Flowmeter
Authors: Nuber Michael , Huber Christof , Rieder Alfred , Anklin Martin , Drahm Wolfgang , Braun Marcel
Published: May 2012

The introduction of the Coriolis mass flow measuring principle was a milestone in instrumentation. By offering the most accurate direct mass flow measurement in situ, combined with the possibility of measuring density at the same time, it enabled customers in a variety of industries to profit from the most convenient metering even in challenging applications, where other measurement principles reached their limits.

Alas the geometrical designs of the meters on the market seemed to have reached a natural barrier at 12" pipe diameters. However, the higher the masses flowing through the pipelines, the more important the lowest error of measurement possible becomes. In hydrocarbon measurement this is apparent.

The paper presents the world's first commercial Coriolis mass flow meter with 4 tubes. The working principle is explained and the geometrical and physical advantages of the 4-tube design compared to existing 2-tube designs are highlighted. The paper also reflects on the mechanical construction of Coriolis mass flow meters in general and highlights the importance of a sophisticated mechanical concept.
Enhancing Production Allocation in Intelligent Wells via Application of Models and Real-Time Surveillance Data
Authors: Wu Xingru , Humphrey Kathryn , Liao Tony T.
Published: May 2012

The accuracy and precision of well rates are paramount in reservoir management, well performance surveillance, flow assurance, and any third party processing arrangements. Rate allocation is traditionally based on well rate tests and downtime. This method is usually time-consuming and thus performed relatively infrequently. This could be inadequate for proactive asset management especially with wells that may produce in transient state.

This paper discusses methodology to improve well rate allocation quality and save engineering time. In practice, many fields face some or all of the following challenges that are related to well rate allocation: 1) reservoir communication, 2) well interference, 3) changing skin factors or other near wellbore boundaries, 4) uncertainties around reservoir fluid properties, and 5) difficulty in obtaining well rate tests for a variety of reasons. For many intelligent wells, it is a common practice to install permanent downhole gauges which are playing critical roles in field management. This paper describes a framework on how to capitalize on the real time data from well pressure and temperature sensors and use the data in Integrated Asset Modeling (IAM) to allocate the well rate with enhanced accuracy, increased frequency, and reduced processing time.

The paper uses Atlantis in Gulf of Mexico as an example to demonstrate this process. The real-time data supported model based allocation process becomes virtual flow meters for the intelligent wells. For Atlantis, field-wide allocation accuracy has been improved from previously +/− 10% error using the traditional allocation method based on well rate test and downtime method to current +/−3% error using the new method. This paper also shows model maintenance is a journey that needs strenuous attention especially after water injections commences and more production wells come online.
Managing Uncertainty of Reservoir Heterogeneity and Optimizing Acid Placement in Thick Carbonate Reservoirs
Authors: Retnanto Albertus , Lynn Curtis , Orellana Edin
Published: May 2012

Effective stimulation of thick, layered carbonate reservoirs is required to reach production targets for present and future demand. It is common that the completed intervals intersect several layered reservoirs, commingle multiple zones, and extend hundreds to more than a thousand feet in length. Even with the best petrophysical measurement and interpretation available in the industry, the key formation parameters considered in acid stimulation are still clouded by uncertainty. Several matrix acidizing techniques have been applied to stimulate these types of reservoirs based on the knowledge of petrophysical data. This paper strives to outline some of the key pitfalls that can occur due to the uncertainty in this data. Using reservoir simulations, the long term adverse impact of these pitfalls on both production and overall recovery can be shown.

A new acid diverter, based on degradable fiber and visco-elastic surfactant technologies, has been applied, along with a placement model, to optimize treatment design and to maximize diversion in heterogeneous carbonate reservoirs. The system is robust, diverting from high permeability streaks, fissures and natural fractures with very little diverting effect from the low permeability zones, and therefore generates a more uniform stimulation than conventional fluid systems. This approach has been used to optimize various stimulation campaigns on carbonate fields throughout the Middle East.

Maximizing treatment fluid coverage across the entire intervals can be achieved across thick, even naturally fractured, carbonate intervals using degradable fiber technology within a visco-elastic surfactant fluid. The diversion technique does not overly rely on certainty in petrophysical data, such as permeability and porosity, and can be successful in a variety of potential scenarios.
Integrated Production System Modeling of the Bahrain Field
Authors: Pothapragada Vijay , Al Kooheji Hamza , Al Hajri Said , Siyabi Ibrahim
Published: May 2012

The Bahrain Field, located onshore Bahrain, consists of multiple producing oil and gas reservoirs. The oil zones have been developed with approximately 1,040 wells flowing into 16 well manifolds and 6 tank batteries. Approximately 3,000 more wells could potentially be drilled in the future. The Khuff gas reservoir has an independent gathering network and has been developed with 45 wells.

Two separate integrated production system models have been built, one each for oil and gas. This paper describes how these models were built, the challenges in maintaining and calibrating these models and the value creation. Both models are used for day-to-day production management under various system constraints and also for long term field development planning.

The oil model has changed how well and system analysis is performed in the asset, as operational and development decisions are being implemented based on the model recommendations. The results are very encouraging, allowing more visibility and credibility for the model's use across various engineering disciplines.

The gas model, although relatively simple compared to the oil model, is the key tool used for optimization and development planning of the Khuff surface network. This model is used to calculate the capacity of the system, helping to ensure that demand requirements are met. The integrated gas model of the Khuff reservoir, wells, gas dehydration units and transmission system is currently being used for studying various long-term field development scenarios to identify the most cost effective way forward.

The concept of integrated production system modeling is gaining ground in the oil and gas industry. This work reiterates that this concept can be applied at any scale from large to small fields, while reaping significant benefits during the life of the field.
Comparison between Conventional and Intelligent Wells with Reactive and Proactive Controls under Economic Uncertainty
Authors: Sampaio M. A. , Barreto C. E. , Schiozer D. J.
Published: May 2012

The exploitation of an oil field in deep water presents many challenges related to high water production, high cost of frequent well interventions and many uncertainties. One of the technologies available, which can overcome these problems, is the use of intelligent wells (IW), which are capable of reducing water production rates, to avoid intervention in the well and to add operational flexibility to mitigate risk. However, the real benefits of this technology are not always clear due to the lack of a consolidated methodology in the literature. Moreover, there are also two main ways of controlling valves, i.e., reactive and proactive controls, making it necessary to better understand them to extract advantages and disadvantages from each one. Therefore, the objective of this work is the comparison between conventional wells (CW) and IW, using reactive and proactive controls. The first control is simpler to be used and quicker to be optimized but the second type can be more profitable, although more difficult to optimize. The optimization method used to solve the problem is an evolutionary algorithm, which is coupled to a commercial simulator to search for the maximum net present value (NPV), based on the ‘shut in’ water cut to determine the optimum time in which to close each valve and the well, in all types of controls. This work employs a model using an inverted five-spot configuration of wells to represent a part of a reservoir under a waterflooding recovery method. Some case studies are used considering different reservoir heterogeneities, type of oil and under economic uncertainty. The conclusion shows that IWs are able to increase production time, oil recovery and the NPV; as a consequence total water production is also increased. The results also show higher benefits in cases with more heterogeneity and light oil. Moreover, IWs using proactive control is better than IWs with reactive control and using either of them is better than CWs.
Safety Mangement in Oil & Gas Industry - The How's and the Why's
Authors: Rizwan M.. , Al-Marri H..
Published: May 2012

Operation management in complex process plants such as major hazard facilities are regularly called upon to make decisions that balance the production and safety requirements of their organization. The process-based rules commonly used in manufacturing and process industries are permit to work systems, risk assessment and job safety analysis.

Job Hazard Analysis or Risk Assessment is a safety management tool in which the risks or hazards of a specific job in the workplace are identified, and then measures to eliminate or control on those hazards are determined and implemented. More specifically, a job safety analysis is a process of systematically evaluating certain jobs, tasks, processes or procedures and eliminating or reducing the risks or hazards to as low as reasonably practical (ALARP) in order to protect workers from injury or illness. It focuses on the relationship between the worker, the task, the tools, and the work environment. As the term ‘job safety analysis’ is not restricted to only identification of hazards, but the implementation of controls (Mitigation plans) and verification of the effectiveness of those controls, the term ‘safety’ will have a more appropriate meaning in the context of assessment of risk in a job. A JSA is a task oriented risk assessment which can be applied by a work team prior to undertaking a potentially hazardous activity. Risk Assessment is a planned procedure in which all hazards in the workplace are identified and their Risk Potential evaluated. The Risk Potential is a combination of the likelihood with the severity if an accident did happen. The first step in any risk assessment is to conduct a hazard analysis.

A Permit to Work System is an important part of an Oil and Gas company's Safety Management System and a key component of a Safe System of Work. A PTW System helps to ensure that all work is planned, communicated, controlled and carried out in a safe manner. Permit-To-Work is a proven best-practice method to ensure safety on dangerous hazardous worksites. A permit is a written, signed legal document and is a means of communication between site management, plant supervisors, operators and those who carry out the work. The most appropriate type of permit is determined and used according to the nature of the work to be performed and the hazards to be eliminated or controlled.

Therefore, it should be emphasized, however, that a ‘permit to work’ is not a replacement for robust risk assessment & hazard analysis, but can help bring the risk assessment ‘to life’, at the sharp end, where it matters.
Adaptation of Scope Challenge and Schedule Optimisation Techniques for Turnaround Optimization
Authors: AI-Kubaisi Nayef S. , AI-Ejji Hamad M. , Prasad Venkata R.
Published: May 2012

The Gas Recycling Plant (RG) of Qatar Petroleum (QP) produces Stabilized Condensate (DSC) and Raw Natural Gas Liquid (NGL). During Maintenance turnarounds (TA) in 2008 and 2012, QP employed new turnaround optimization techniques, which minimized the scope of work and the downtime duration of the plant outages. These two techniques were: Scope Challenge (SC): The complete scope of work of the TA is challenged in terms of monetary benefit to QP. The plant's integrity, Operation's requirement, shutdown sensitive items, mobilization requirements, and resources are given due consideration during the review process.Schedule Optimization (SO): The finalized scope of work is broken down into activities. The resources, costs and duration estimates are provided for each activity. The critical paths are identified and the duration of activities in them are re-evaluated using a systematic approach. Activities of various stake-holders are integrated into the schedule and interfaces are examined while optimizing the critical paths.

This paper discusses the approach, adaptation, implications, financial gains and benefits of utilizing the above techniques in gas recycling plant turnarounds.
DOST to ODVision2020
Authors: Al-Qahtani E.. , Soni R..
Published: May 2012

DOST – Directorate Operations Strategy Team was formed in year 2007 to develop Operations Directorate long term vision. Inspired by Qatar National Vision – QNV2030 and fuelled by Qatar Petroleum "Commitment to Excellence", DOST has made significant strides in developing a shared Operations Directorate Vision – ODVision2020 under an innovative and unique LEADERSHIP concept.

This paper highlights the DOST journey in establishing the Operations Directorates Mission, Vision and Values as well as developing broad Objectives, Strategies and Roadmap based on SWOT analysis, cultural surveys and interviews carried out across the ranks. The paper will also present the challenges anticipated in realization of ODVision2020 and how organizational people, processes and systems would be transformed and Operations Directorate emerges as a leader in the industry in all aspects of its business.
Gas Flaring Reduction Initiatives in Dukhan Oil & Gas Field
Authors: Al-Bidaiwi M. S. , Beg M. S. , Al-Muhannadi M..
Published: May 2012

Qatar Petroleum is committed to trying to achieve zero gas flaring. We have carried out important field changes to reduce it. As a result, we have significantly reduced gas flaring, recovered more hydrocarbons, protected the environment, and made financial gains by optimum utilization of the field existing infrastructure.

Gas Flaring is an important aspect of oil and gas field operations. It provides a safe relief for the production facilities whenever excess fluids or out of specification products need to be released. However, it has an adverse effect on the environment that needs to be resolved. Also valuable by-products could be recovered.

QP applied environmental regulations and drew on our experience to evaluate flaring sources and devise plans to mitigate flaring. We used recommendations from our evaluation studies to identify the necessary operational actions and plant changes.

We have identified four main factors affecting flaring: 1) field development planning 2) the design, construction, operation, and maintenance of field processing facilities 3) investment economics and 4) regulatory instructions. The operational actions and plant changes that we made have reduced gas flaring. Many other projects and studies are in progress to reduce flaring and ensure we comply with environmental protection requirements. This article explains the Qatar Petroleum flaring philosophy and the changes and modifications completed or in progress in Dukhan field that reduce flaring as we aim to achieve ‘Zero Flaring.’
The First Relief Well Drilled in Qatar to Intersect, Kill, and Abandon an Underground Blowout
Authors: Al-Murri Talib , El-Faghi Fawzi , Al-Meer Khalid
Published: May 2012

While executing a workover operation, one of the wells in Dukhan oil field experienced a well control problem. Water, Oil and gas from underground started to flow to surface through the production tubing. The BOP shear rams where activated to stop the flow. During the attempts to bring the well under control, an uncontrolled flow of oil, water and gas with considerable H2S concentration occurred from the ground.

A relief well, which was the first relief well in the State of Qatar, was drilled to intersect the blowout well and stop the flow.

A considerable amount of engineering and planning was involved to bring the well under control, along with stringent operational and safety controls. The operation was implemented in a safe and professional manner in 46 days, and resulted in an effective and long-term isolation of the blowout well.

The objective of this paper is to discuss the blowout well, the relief well, and the intersecting and killing operation.
Success Story of Solvent Swap in Acid Gas Removing Unit
Authors: Al-Ruwaili Soud Jaleel , Das Beni Prosad
Published: May 2012

This article explains how Qatar Petroleum faced the difficulties using diethanolamine solvent in its operating acid gas removing unit and were resolved them by solvent swap.

Gas recycling department's specialized team conducted root cause analysis to identify the operating problems encountered using diethanolamine solvent. Furthermore, the team carried out techno-economic feasibility studies to establish selection of suitable solvent to minimize and control filtration, plugging and foaming in the acid gas removing unit.

In addition, the team asked different suppliers to submit selection of alternative solvent to compare benefits and viability of replacing diethanolamine solvent. After analyzing the benefits, specialty methyldiethanolamine (Aminosol CST 115) was selected among other alternative solvent and finally solvent swap was carried out. The result of replacing diethanolamine with specialty methyldiethanolamine reduced yearly maintenance and operating cost with a full amount of to 0.52MM QAR, yearly cost savings with a full amount of 1.5MM QAR and expected a payback period within 10.5 months.

This paper will discuss acid gas removing unit facility and process overview, root cause analysis, investigation and troubleshooting of operation problem and challenges, the selection of alternative solvent and operational benefits of solvent swap.
Use of Liquid Resin to Enhance and Maintain Conductivity in Fractured Wells Better Than Use of Curable Resin Proppants: A Case from Burgos Basin
Authors: Araujo Oscar , Rodriguez Levi , Lopez Elias , Bailon Leonel
Published: May 2012

Burgos is the first major unassociated gas basin in Mexico. It covers an area of 50,000 km2 and contains complex, sandstone reservoirs, which are highly compartmentalized and made up of several small, independent blocks characterized by low permeability. This basin is considered a tight-gas reservoir. Sustaining a high production level in this area requires a large number of wells to be drilled and hydraulically fracture stimulated. Historically, the initial well productivity is high, but declines quickly. This phenomenon seems as if it could be associated with the loss of fracture conductivity shortly after the well is put on production.

Proppants that are factory coated with a partially cured resin, generally referred to as resin coated proppants (RCPs) have been used in the industry to reduce proppant flowback and to improve fracture conductivity. A more recent methodology is to coat proppants on location using liquid-resin systems (LRSs). This method uses a specific type of hydrophobic material to resin-coat proppants, and has often been used in the industry specifically to prevent post-frac proppant flowback. The proppant is coated on-the-fly on location with the LRS material. This technology has also proven to both initially increase and also to better sustain fracture conductivity over time. The use of liquid resins for proppant coating in the Burgos basin to enhance and maintain conductivity in several fields has shown to lead to better well performance than when using the factory-coated RCPs.

Production data from a LSR treated well after almost two years of production is presented and compared to a well with similar petrophysical characteristics completed in the same productive block in the same formation using the same volume of a RCP type proppant.

The similar conditions initially present in these wells will forcefully support the superior behavior of LRSs when compared to conventional RCPs when placed using identical treatment designs.
How to Meet "Zero Discharge" Goal in a Sensitive N. Azadegan Field Wetland Environment?
Authors: Rong Li , Yaping Feng , Yunzhang Zhou , Deyin Yang , Zhi Jiang , Guoqiang Bi
Published: May 2012

North Azadegan field with more than 4,886MMSTB reserve to drill 58 wells in less than 3 years, operation area with average about 2.5m water depth, belongs to one of International Nature Reserve Conservation Zones faced with a huge environmental challenge. Traditionally onshore operations in Iran, water based drilling mud and its cuttings have been disposed of directly on the ground in unlined pits, because disposal of drilling wastes poses no serious threat to the environment. However, a Zero-discharge goal is required for this sensitive wetland of N.Azadegan field.

This paper shares an overview of how to achieve a zero discharge goal in a remote, rural, sensitive wetland, accompanied with the below applicable methods: 1)Cluster well pad design and construction including waste treatment layout; 2)Generic waste management stream for minimizing contamination; 3) Treatment of drilling cutting waste as pavage for other pads or road construction; 4) Reuse of waste water for mixing mud etc. While contractor's waste management equipment and personnel daily rates add to the drilling operation cost of the project for higher cost ceiling under Buy-back contract, cutting treatment and mud reuse techniques actually reduce total N.Azadegan project cost, combined with careful planning, advanced equipment and services. This paper will report the past experiences and lessons of these waste management methods in N.Azadegan. In details, the waste treatment and management technologies integrated with well pad construction will be evaluated feasibly and economically.
An Innovative In-situ Natural Gas Lifting Approach to Produce High Pour Point Oil with High Output: A Case Study
Authors: Tang Xueqing , Li Guocheng , Yu Keqiang , Cai Bo , Wang Ruifeng
Published: May 2012

This paper demonstrates an innovative in-situ natural gas lifting approach, which has been successfully applied in AG pool of FN field, Sudan. AG pool is a series of edge water driven stacked sandstones with light oil and natural gas pools, and mostly natural gas zones are below oil zones. AG oil is typical of high pour point, ranging from 37 to 57 Celsius degree. Possibility of wax deposition posed great production and operational challenges at 27 Celsius degree surface temperature. Gas below oil pool could serve as in-situ gas lifting to boost production and reduce wax deposition. This process undergoes tubing produced natural gas flowing simultaneously into annular to lift oil production in the same wellbore. This process has been optimized by following approaches: 1) establishing screening criteria of qualified gas and oil zones for lifting; 2) Partial completion and reduced perforation density in gas zones for controllable gas rate; 3) Separators deployed to remove portion of gas for smooth transportation to facilities.

4 producers have undergone in-situ gas lifting since 2009, average well output achieved 2 to 4 times of DST rate, amounting to 2000 to 4000 BOPD with low water cut. Up-efficiency has been above 85% without wax deposition problems. Operational costs were greatly reduced. Conclusions drawn from successful in-situ gas lifting application were:1) selected oil and gas zones fully qualified for gas lifting; 2) optimized in-situ gas lifting brought high output and low water cut; 3) innovative wellbore structure and facilities design replaced the use of pumps and saved costs.

Sudan is abundant in stacked oil and gas pools with high pour point, therefore in-situ gas lifting has wide applications.

Successful in-situ gas lifting in this paper highlighted significant oil rate gain without oil gelling problems, cost-effective wellbore structure and facilities design, give a staircase for future wider applications.