bluuebunny/crossref_metadata_2025 huggingface dataset:
Use of Distributed Temperature Sensing for Wax Detection and Treatment Optimization
Authors: Guzman Manuel
Published: May 2012

State of the art technology has been incorporated into the Seria North Flank waterflood development. Both producer and water injector wells are completed with interval control valves, distributed temperature sensing (DTS) and downhole gauges. DTS has been commercially available for more than a decade, however only recently it has been employed in the oil industry. Interpretation of the data has been difficult and therefore its value questioned.

This paper presents an original technique of monitoring wax build up through the use of the DTS data. PVT analysis from the appraisal well showed significant wax content in some of the reservoirs to be produced. The critical wax deposition temperature is higher than the surface temperature and therefore wax is expected to be deposited inside the tubing. The DTS provided temperature trends that showed temperature decline in a section of the tubing string; caused by the additional layer of wax between the crude oil and the gas filled annulus. The paraffin layer has its own heat transfer coefficient therefore thickness can be estimated from temperature data for unchanged flow rate and fluid composition.

Using the temperature trends, the Well and Reservoir Management (WRM) team was able to determine the exact depths where the wax accumulated. This information avoided slick line interventions to determine hold-up depths and also allowed the required volume of solvents to be calculated, prior to for coiled tubing clean out. The Coiled Tubing activity enabled production to be maintained before the wax build-up could significantly impact the well flowrate. This technique has been extended to other wells and is now part of the standard WRM monitoring parameters for this field.
Brownfield Project Interface with Operating Facilities without Impacting Schedule & HSE Compliance
Authors: Zayene Hassan , Desai Hitesh K.
Published: May 2012

Brownfield Projects (i.e Projects involving Execution within or associated with Operational Process Plants) provide unique challenges for compliance to Health, Safety and Environmental (HSE) Regulations everywhere in the world.

While HSE Compliance is essential and mandatory, the associated procedures are often tedious and time consuming; even overwhelming the Operations personnel and adversely impacting project schedules. One such project is the Gas Sweetening Facilities (GSF) Project, consisting of one Acid Gas Recovery Unit (AGRU) inside the ARAB-D Plant at DUKHAN and one Sulfur Recovery Unit (SRU) inside the NGL Facilities at MESAIEED. This Paper highlights the measures taken at the AGRU to meet the apparently conflicting requirements of HSE Compliance and SCHEDULE Compliance.
Deal With Start-Up and Commissioning Threats and Challeges at an Early Stage of the Project for a Sucessful Handover and Project Completion
Authors: Al-Bidaiwi M.. , Beg M. S. , Sivakumar K. V.
Published: May 2012

The normal practice in the oil & gas industry is to implement major projects through Project Management Team by engaging external contractors. The operations team is involved only for specific activities and mostly during commissioning and start-up. Qatar Petroleum involved Operations team from the early stages in two of its major projects implemented in Dukhan fields and experienced successful implementation of the projects by meeting the project schedule and cost, smooth handover of the facility and achieved the intended objectives with adequate safety and operational flexibility.

QP-Dukhan's Operations team played a major role in providing clarity and coherence of project objectives among various divisions and geographically diverse contractors. Operations contributed immensely in many aspects such as provided site specific data to tailor the design to suit site conditions, identification and mitigation of operations risks at design stage, reviewed the design to achieve targeted production, product quality, adequacy of safety systems, met environmental regulations, ensured operational flexibility, dealt with interface issues, ensured operation and maintenance philosophy to suit Dukhan conditions, utilized synergy with exiting facilities, incorporated past experiences in design and provided site coordination.

Involving Operations early helped us to capture many issues in the early stages of the project. These were successfully incorporated in the design. This resulted in minimal re-design and re-engineering and helped us to firm up the scope of EPIC contractor and avoid project delay and cost over-run. Moreover, commissioning and hand-over was very smooth and plant reached its design throughput without major startup problems and delays. The projects met their design objectives with adequate safety, integrity and operational flexibility and integrated very well with other facilities in Dukhan. This successful experience led QP to create a new division within the Dukhan Operations, dedicated to coordinating continuously all other projects.
Moving Towards Intelligent Oilfields
Authors: Al-Sulaiti A. S. , Al-Baker H.. , Beg M. S.
Published: May 2012

Qatar Petroleum (QP) is implementing intelligent oil field (IOF) concept in its operated field. This paper traces the development of projects which are completed as well as which are in progress. The paper also presents a case of how Dukhan oil field is well positioned to move towards a fully integrated intelligent oil field.

Successful IOF implementation can yield increased operational performance and extend field life through collaboration, optimized work processes and advanced technology.

Dukhan field present status was assessed using the maturity model and a roadmap for implementation was suggested. For the last ten years, Dukhan operations have moved steadily towards real time monitoring, control and infrastructure capabilities.
Development and Implementation of a Health Safety And Environmental Management System In The Qatar Petroleum Drilling Department
Authors: Balogun Tokunbo Gbolagade , Andaila Ali Moshin
Published: May 2012

Onshore and offshore oil and gas exploration and drilling activities present complex challenges with regards to Health Safety and Environmental (HSE) management. With growing energy demands worldwide, the need to optimize production potentials is pushing the industry to new frontiers for untapped reserve, thereby increasing HSE exposure and challenges. In addition, the scale and magnitude of both economic and reputational impact of past and recent incidents in the industry suggests that a business continuity model without a proper HSE management in place will be inadequate.Qatar Petroleum (QP) drilling department recognized the importance of an effective HSE management system to deliver on the business objectives with minimal HSE related impact. To achieve this, we adopted the templates presented by ISO14001:2004 for Environmental Management System (EMS) and OHSAS 18001:2007 for Occupational Health and Safety Management (OH SMS).This paper outlines how HSE management system can be developed and effectively implemented with minimal cost and within a limited timeframe using QP drilling department experience as a reference.
Operator Performance Enhancement by Alarm Management
Authors: Mahajan Sachin Ashokrao , Surve Vikram Genuji
Published: May 2012

The Gas Recycling plant of Qatar Petroleum, Dukhan had a tough time in dealing with huge alarms generation. Gas recycling is a big integrated process plant and has one central control room where all the unit operations are controlled. Because of the nature of the process lot of alarms are generated and most of them are for operator information purpose and do not require any operator intervention.

There were 27,000 alarms configured. And there were three common problems with alarms, Standing alarms, Background alarms or bad actors and alarm floods. There was no alarm philosophy, alarms were constantly added and rarely deleted. Alarm limits were rarely revisited. The panel operators approach was reactive to alarms as constantly alarms were generating. To deal with alarms problems, the alarm management project was implemented.

This paper will describe in detail the ongoing alarm management project in the Gas Recycling plant, QP Dukhan and aims to provide all the details of project design stage, alarm philosophy, implementation techniques and the initial benefits achieved.

The roadmap used for alarm management project includes developing the alarm philosophy, alarm rationalization, implementing the alarm changes in the DCS configuration and benefit retention. The alarm philosophy designed based on the EEMUA guidelines. The benchmark values set by the EEMUA are chosen as the project KPI targets.

The implementation of the Alarm management project require lot of involvement by the process engineer, system engineer, instrumentation engineer and experienced control room operators for rationalizing the alarms. The initial results after ongoing implementation of the alarm management projects shows that the average alarm rate per 10 minutes has improved drastically from 6.5/10 min to 1-2 alarms/10 min which is very close to the EEMUA set benchmark values. The benefits achieved due to reduction in the alarms are more productive and positive workforce and improved safety.

The overall conclusion that can be drawn from the data collected is that the steady state alarm rate has been reduced to a manageable level and the EEMUA target of less than 10 alarms per 10 min period during flood is a challenge with today's technology and practices.
Utilization of Excess Flared Gas from Gas Lift System as a Gas Injection -An Innovative Method to Reduce Emissions and to Save Energy
Authors: Janitra E. S. , Saputra R. R. , Rohman A. F.
Published: May 2012

Kaji-Semoga fields in South Sumatra, Indonesia, are oil fields with a gas lift population of almost 50%. Since there is no gas source available in Kaji-Semoga fields, both the gas lift and fuel system are dependent on produced gas from oil producing wells. Based on an overall review of the gas lift system, the flare is inefficient. Pressure Control Valve (PCV), which controls the flare, is opened when the gas lift pressure reaches 815 psig, yet only 800 psig is needed for a normal operation. The gas lift pressure usually exceeds 815 psig, hence gas is flared. On the other hand, compressor suction often drops below the safety level. To overcome this problem, KS-X (Telisa gas cap) is produced around 1-2 MMSCFD. The production of Telisa gas cap has a very negative impact on this formation, causing a decrease in reservoir pressure of 60% in just 4 years.

Since Telisa reservoir pressure has depleted from 900 psig to 400 psig, it is easy to inject excess gas from the flaring system. PCV is added to the gas lift system and is set at 805 psig to open. The current gas lift line at KS-X has also been modified to be able to inject the excess gas to the well via the installed gas lift valve. Based on the daily record, the injection system is able to save flared gas and reduce produced gas from Telisa Kaji by up to 1 MMSCFD. Both gas lift system and compressor suction pressure are also relatively more stable after injection.

It is concluded that the recycle-injection system is a proven and practical method to use in mature fields where there is no gas reservoir available as a fuel source. The system is able to save up to 1 MMSCFD of flared gas worth $8,000 per day (based on the local market gas price).
ESP Retrievable Technology: A Solution to Enhance ESP Production While Minimizing Costs
Authors: Szemat Vielma W. E. , Drablier D.. , Petry M. L.
Published: May 2012

The easy oil production is gone and current field developments require new approaches to produce oil and gas reserves in the most effective, economic and safe ways. Around the world, more than half of the wells are assisted by an Artificial Lift (AL) system. The use of these AL methods opens a range of opportunities to produce from low pressure reservoirs, low GOR, high water cuts and many others constrains that operation & production engineers are facing nowadays. Electro Submersible Pumps (ESPs) are widely used around the world as one of the most common solution for the current field development conditions.

However, ESPs represents a challenge itself in terms of production management, intervention cost and run life cycle. Eventually, all ESPs will fail and the need of a workover will be present repeated times during the well life; and many causes of failure are beyond the control of either manufacturer or operator.

To solve this issue, several types of ESPs deployment systems were designed and are currently in use around the globe (e.g.: standard tubing deployed, thru tubing conveyed, CTU deployed), but each one of them has its own limitations.

In order to enhance ESPs installation conditions, capabilities and run life management, a new approach resulted on the design of an ESP Retrievable system that will complement current major ESP providers' equipment portfolio. This technology gives the operator the opportunity to retrieve and rerun the ESP without a rig intervention by only using WL, sucker rods or CTU equipment.

The technology can be used either onshore or offshore to manage and optimize oil production by taking aside the rig need to change the ESP. This improves the oil recovery, minimizes environmental impact and increases the field safety management while reducing the overall well cost.

This paper will explore the technology design, capability and constrain, cost analysis and will conclude with installation experiences and results.
Impedance Analysis as a Tool for Hydraulic Fracture Diagnostics in Unconventional Reservoirs
Authors: Rahmani Amir Reza , Shirdel Mahdy
Published: May 2012

Production from unconventional reservoirs plays a key role in supplying hydrocarbon to the world's increasing energy demand. Hydraulic fracturing is one of the most advancing technologies in producing hydrocarbon from low-permeability reservoirs, especially in tight and shale formations. The geometric properties of a hydraulic fracture affect significantly the production rate from these stimulated reservoirs. Therefore, it is of utmost importance to characterize the geometric features of hydraulically-inducedfractures during stimulation processes.

The geometric properties of a hydraulic fracture change with fracture evolution due to stress propagation along the cracks. We have modeled such a system based on the analogy between fluidic and electric circuits. The model takes into account the dynamic alteration of hydrodynamic impedance of the fracture. The hydrodynamic impedance controls the relation between the fracture fluid flow rate and pressure drop during stimulation process. The proposed model incorporates the effects of both hydrodynamic capacitance and resistance of the fracture and the wellbore to compute the fracture impedance.

Downhole measurements of pressure and flow rate can explicitly determine the hydrodynamic impedance of the fracture. Fracture impedance can also be implicitly inferred from wellhead pressure and flow rate measurements. The pulsatile nature of hydraulic fracturing treatment makes it sensible to utilize the wellhead data for the purpose of impedance monitoring based on the electromagnetic transmission line theory.

We have performed extensive sensitivity analyses on the most important parameters of a single hydraulic fracture for assessing fracture impedance. These parameters include fracture thickness, fracture radial extent, and fracture shape. Through sensitivity analyses results and real-time measurement of fracture impedance, we infer the basic geometric properties of a hydraulic fracture.

This research has led to an analytical approach for evaluating hydraulic fractures geometric characteristics. The approach builds an intuition toward better understanding how to design hydraulic fractures in a more efficient fashion.
Saudi Arabia's Artificial Island Wells: Smart Thinking, Huge Rewards for Smokeless Flowback Option
Authors: Dhufairi Mubarak , Arukhe James , Al Ghamdi Saleh
Published: May 2012

One of the current largest oil increments in the world in Saudi Arabia is undergoing field development. The southern part of the field traverses the Arabian Gulf Sea. The Production Engineering team crossed major hurdles in the development of this field with Causeways construction on artificial islands over drill sites to assess well sites.

Flowback options on wells in these drill sites to unload drilling fluids presented key challenges. The flowback objectives included well cleanup, stimulation, production logging, and extended well tests for reservoir characterization requirements. Flowback would also allow conducting electric submersible pumps (ESP) spin tests prior to ESPs installation.

A smokeless flaring option considered the heavy crude's characteristics with relatively high H2S content, possible emulsions from intermixing with completion fluids, interwell spacing limitations, and the sensitive nature of the nearby challenging marine environment. The choices were between using a conventional flare system and modifying the proposed layout to optimize the project's objectives while respecting the constraints imposed by a sensitive aquatic environment, highly sour crude, space limitations, and work conditions or implementing pre-existing conventional practices with the attendant risks of compromising health, safety, and environment.

The authors examine the processes leading to the implementation of a smokeless and an environmentally friendly flowback option. The discussion includes the modifications made to the burner system, and H2S removal from the gas and oil phases. Also a new methodology is presented that fully controlled oil and gas flow to the burner to mitigate the risk of burner flameout for the highest burning efficiency, minimizing spills, and enhancing safe operation. The authors examine the pros and cons of other welltest options such as to re-inject produced fluids into the same reservoir, different reservoirs, or injection into water injectors.

Key significant technical contributions include the presentation of several practical measures to avoid oil spills, and to guarantee ambient air quality. The welltest layout included several automation systems or the elimination of human interventionto deliver safely the project's objectives.
The Agbami Intelligent Well: Examples of Active Reservoir Management
Authors: Collins J. R. , Neubauer E. B.
Published: May 2012

Agbami is a deepwater oil field located offshore Nigeria in the Gulf of Guinea. The field has been online since July 2008 and has produced over 275 MMBO to date. The Turbidite depositional setting has lead to a complex stratigraphic architecture with reservoirs being broken into distinct subunits. Although initially in thermodynamic equilibrium they posed dynamic challenges of conformance control and differential depletion. For this reason, Intelligent Well Completions (IWC) were installed throughout the field in both injectors and producers. The field development currently consists of 39 completions across 21 wellbores which are individually isolated and controlled via Interval Control Valves (ICV). Combined with multiple downhole pressure/temperature sensors and inline flowmeters the Agbami IWC provides the real time surveillance and control necessary for optimization of field performance and recovery.

During development planning, identifying the potential value from the installation of IWCs and deciding on or recognizing their possible applications is often not a trivial one. The value can be hard to quantify where the information impacts multiple decisions, there is limited in-house experience or where robust forecasts are difficult to generate. The objective of this paper is to bridge some of these gaps through providing an overview of the application of the IWC within Agbami from the workstation of the Production Engineer. Although often overlooked at the early stages of field development, IWCs can provide significant value to the Production Engineer who focuses on the short to midterm field performance and long-term completion reliability.

The paper will cover specific examples of value added in relation to production performance over the last three years of field history. IWCs are used actively by the production engineering team with the objective of prudent reservoir management through integration of their capabilities into surveillance plans, production management practices and production optimization efforts.

The expanding employment of IWCs for existing or new field developments warrants further literature which shares detailed examples of IWC practices and benefits. The intention of this paper being to focus on the production engineering aspects and values of the IWC as it has been utilized within Agbami at the operations level to improve reservoir management.
Integrated Production Optimization and Surface Facilities Management through Advanced Optimization Techniques
Authors: Giorgio Viadana , Danilo Albani , Marco Distaso , Almatasem Sharon
Published: May 2012

The Production Optimization is one of the most complex and multi-disciplinary task in the oil&gas industry from an operational point of view: it involves the surface asset during all its production life and requires a continuous improvement process. In the gathering facilities and process plant engineering design, the optimization is driven by inputs that are subjected, during the asset life, to changes; this fact, coupled to improvements and modifications in surface facilities, creates the necessity to manage and optimize production scenarios with a more frequent time-frame. Technology improvements have enabled a widespread use of integrated simulation models for a better asset management to be fully combined with measured field data. In this paper we present a dedicated workflow for surface facilities – gathering system and process plant – production enhancement and management coupled with an advanced optimization technique based on a powerful algorithm. The main feature of this algorithm – and consequently of the proposed workflow – is the ability to control many variables simultaneously according to the system constraints even with complex, conflicting and non-direct interconnections between them and the objective to be reached. It has been proven that this algorithm has a robust practice that detects the global optimum of the feasible area avoiding a premature stop in a local optimum region, a situation quite common in highly-constrained and non-linear optimization problems in oil&gas industry. The technical contributions of the work are the abilities to support operations in: definition of field potential, production optimization and de-bottlenecking activities. In the paper a case study, based on a highly-constrained field with gas treating limitations, is reported and the proposed workflow's results are compared with another integrated optimization available from other software, showing an improved ability to detect global optimum combining well management to the plant capabilities.
Simultaneous Well Stimulation and Scale Squeeze Treatments in Sandstone and Carbonate Reservoirs
Authors: Jordan M. M.
Published: May 2012

In many oilfields the relatively small number of high-cost, highly productive wells, coupled with a carbonate and or sulfate scaling tendency (upon waterflood breakthrough of injected seawater) requires effective scale management along with removal of near-wellbore damage in order to achieve high hydrocarbon recovery.

The nature of the well completion strategy in new fields such as frac packs for sand control and acid stimulation for carbonate reservoirs had resulted in some wells with higher than expected skin values due to drilling fluid losses, residual frac gel, fluid loss agents, and fines mobilization within the frac packs where applied.

The paper will present how the challenges of managing impaired completions and inorganic scale forced innovation in terms of when to apply both stimulation and scale inhibitor packages to sandstone and carbonate reservoirs. This paper will outline a novel process for non-conventional batch chemical applications where bullhead stimulation treatments have been displaced deep into the formation (>20ft) using a scale inhibitor overflush. Not only does this benefit the stimulation by displacing the spent acid and reagents away from the immediate wellbore area, but the combined treatment provides cost savings with a single mobilization for the combined treatment. The paper will describe the laboratory testing that was performed to qualify the treatments for both sandstone and carbonate reservoirs. The four field treatments that were performed demonstrate how these coupled applications have proven very effective at both well stimulation/skin reduction and scale inhibitor placement prior to and after seawater breakthrough in a sandstone reservoir. The lessons learned for the evaluation of the carbonate core via coreflood studies will also be presented.

Many similar fields are currently being developed in the Campos basin, Gulf of Mexico, West Africa and Middle East, and this paper is a good example of best-practice sharing from another oil basin.
Methods of Isolation and Diversion for High Rate Carbonate Acidizing
Authors: Entchev Pavlin B. , Shuchart Chris , Burdette Jason , Rosenbaum Darren
Published: May 2012

Some form of acid treatment is generally required when completing wells in carbonate reservoirs. The treatment objectives range from near well damage removal to true stimulation, using well work techniques that range from acid washes to acid fracturing. All depend on delivering the appropriate acid volumes to the right intervals at the rates needed to achieve the desired results. Because most carbonate reservoirs feature multiple layers, implementation often requires a combination of isolation – separating a particular zone so it alone receives treatment – and diversion, directing the acid from zone to zone as the treatment progresses. Conventional elements of the acidizing toolkit include mechanical plugs, limited entry perforating, ball sealers, and a variety of chemical and particulate diverting agents.

In long deviated completion intervals, a multi-stage perforation / stimulation approach was previously developed and implemented. Successful stimulation and resulting productivity of all target intervals was achieved through a combination of selective perforating, high-rate acid injection, fluid diversion, and linking stimulation results to long-term performance. However, in wells with existing perforations, this approach is not possible. Use of high rate and diverter fluids alone may not provide sufficient diversion to achieve the desired stimulation effectiveness.

This paper describes the initial development of an innovative destructible ceramic plug and seat system as an alternative option for diversion or acid placement during multizone acid treatment. The plug would enable acid diversion in multizone reservoirs with large pressure differentials and/or permeability contrast between the zones. The design and testing of the plug system included Finite Element Analysis (FEA) modeling of the plug, manufacturing of the plug and seat, mechanical strength testing and destruction testing.
The Controlled Freeze Zone Technology™ for the Development of Sour Gas Resources
Authors: Valencia Jaime A. , Mentzer Beverly K. , Denton Robert D. , Mart Charles J.
Published: May 2012

Controlled Freeze Zone™ is an efficient single-step cryogenic distillation process for the removal of carbon dioxide, hydrogen sulfide and other impurities from natural gas. Rather than avoiding the freezing of CO2 at cryogenic temperatures, the solidification is allowed to take place, albeit in a very controlled fashion. The technology has shown the potential to more efficiently and cost-effectively separate carbon dioxide and other impurities from natural gas, and to discharge these contaminants as a high-pressure liquid stream ready for underground injection, either for enhanced oil recovery applications or for acid gas injection disposal.
Towards Next Generation of Smart Fields Using Intelligent Online Multi-Objective Control
Authors: Mikkelsen Lars Lindegaard , Jørgensen Bo Nørregaard
Published: May 2012

Production optimization for offshore oil and gas production is in general a challenging task, even at fields operated "Smart" with continues 24/7 optimization, due to the intrinsic complexity of the domain. In this paper, we present an intelligent multi-objective-control-software approach for the next generation of Smart Fields.

At the DONG Energy E&P operated Siri area, which we use as a test case, several optimization studies have shown that an increase in production throughput is possible, if the comfort zone, i.e. the band between the actual and the maximally possible production level, is reduced dynamically. Maximal production will be obtained when the comfort zone meets the minimally required margin that ensures a safe and stable production in all constraining systems of the installation. This can be hard for the control operators to achieve with the present complex dynamic production configurations.

In our approach, we focus on intelligent online control to minimize the comfort zone by pushing the production towards the process constraints which always have to be satisfied. The new intelligent online multi-objective control system is implemented as a stratified multi-agent system allowing control concerns to be dynamically introduced, changed or removed without the need to modify or inspect the existing control system. The stratified approach supports multi-objective optimization in all layers, i.e. in contexts of strategy, tactics and operation. Optimization conflicts are dynamically identified and propagated to a higher layer. The "irony of automation" predicts that more advanced automation systems require more tacit knowledge; an essential property of any advanced control system is, therefore, the capability to identify and explain optimization conflicts well in advance.

In this paper, we demonstrate that it is possible to continuously minimize the comfort zone and thereby gain higher production throughput by using intelligent online multi-objective control, even at fields with complex configurations.
Examination of Hydraulic Fracture Production Modeling Techniques
Authors: Akuanyionwu Obinna , Elghanduri Khaled , Mokdad Belkhir , Norris Mark
Published: May 2012

Advanced hydraulic fracturing has become a complex and investment intensive operation; hence, predicting its performance has become more important than ever. Robust prediction of production profiles for hydraulically fractured wells is imperative for optimizing the fracture scheme for productivity and determining completion economics. Various methods are currently being applied to modeling production after hydraulic fracturing treatments ranging from traditional analytical methods to semi-analytical and advanced numerical methods. A key requirement for any production modeling approach is the ability and flexibility to cope with uncertainty in fracture, reservoir and well properties to optimize fracture design.

In this study, we applied different modeling techniques to a range of fracture treatment scenarios and compared several real case studies and examples from the North Sea area. A number of factors had to be taken into account during the selection of a particular production modeling technique. These factors included considerations related to well type, fracture design, extent of geological and petrophysical properties, availability of data and ready reservoir models, and turnaround time. Multiple simulations generating multiple production profiles were carried out in most of the cases to support uncertainty bracketing and guide informed decision making even in areas extending to completions optimization.

The results reflect the need to curtail the use of simplified models and approaches when sufficient data is available or where data can be integrated to further reduce uncertainties on a case-by-case basis. On one hand, hydraulic fracturing treatment can be capital intensive while on the other hand, profitability is often a dynamic and changing parameter. Hence, longer term productivity benefits (post fracturing) require explicit and realistic pre-evaluation. Finally, the work highlights robust approaches for uncertainty handling within the production modeling workflow.
Using Advanced Water Treatment Technologies To Treat Produced Water From The Petroleum Industry
Authors: Dores Raul , Hussain Altaf , Katebah Mary , Adham Samer
Published: May 2012

Produced Water (PW) is the water trapped in underground formations that is brought to the surface along with oil or gas in extraction operations and it is the highest volume liquid waste stream generated by the petroleum industry. Historically, the treatment of PW has been limited to free oil and suspended solids removal and subsequent discharge into water bodies or deep injection in disposal wells. Only a small fraction of the PW is currently being treated to an extent that allows it to be recycled & reused.

However, due to any of a variety of factors including legislation, geological restrictions and local water scarcity, the future will require a greater fraction of the PW to be extensively treated and ultimately recycled & reused. The petroleum industry will have to change how it has historically been managing PW and start to consider PW as a "by-product" of strategic importance and value and not as an operational liability.

This paper focuses on the application of Advanced Water Treatment Technologies (AWTTs) for the treatment of PW. The specific technologies presented include direct membrane filtration, biological treatment in membrane-bioreactors (MBRs), thermal evaporators and advanced oxidation processes (AOPs). In addition to describing their respective advantages and disadvantages, this paper also presents examples of case studies where PW is being treated and recycled & reused through the application of AWTTs in full scale facilities.

This paper also presents a brief overview of a laboratory investigation carried out by ConocoPhillips GWSC, where various treatment processes (membrane filtration, biological degradation, membrane distillation (MD) and ozonation) were evaluated as PW treatment methods.

The case studies reported demonstrate that thermal evaporators and membrane filtration technologies have been proven at various installations to be cost-effective at the full-scale for PW treatment. Data reported in this paper also reveal that PW can be successfully biodegraded or chemically oxidized and hence processes such as MBRs and AOPs, which have been successful in other industries but overlooked by the petroleum industry, will need to be considered. In the long term, hybrid technologies such as MD may also become a cost-effective alternative to treat PW.
Triazine-Based Scavengers: Can They Be a Potential for Formation Damage
Authors: Al-Duailej Yaser K. , Al-Khaldi Mohammed H. , Al-Kulaibi Saleh A.
Published: May 2012

Hydrogen sulfide (H2S) scavengers have been used extensively in different field operations such as drilling and acid stimulation treatments. Typically, H2S scavengers are preliminarily designed to react effectively at different in-situ conditions. For example, Triazine-based scavengers are designed for neutral-high pH conditions, while aldehyde-based scavengers are intended for low pH conditions. However, reaction products of these scavengers with H2S could lead to potential formation damage.

The efficiency of two Triazine-based H2S scavengers were investigated over a wide-range of parameters: solution pH value, temperature and exposure time. Additionally, the effects of both scavenger concentration and its ratio to H2S gas on the scavenging capacity were explored. In this work, the scavenger concentration varied from 1 to 5 vol%, reaction temperatures up to 50°C.

Earlier studies have shown that, at low pH, triazine-based have a very low efficiency in scavenging H2S because the hydrolysis rate of triazine is faster than the reaction rate with H2S. Nonetheless, in this study, it was found that long exposure time between triazine-based scavengers and H2S can result in significant scavenging efficiency even at low pH values. Doubling the exposure time had almost doubled the amount of scavenged H2S in acidic solutions. In addition, this work, for the first time, highlights the possibility of calcium sulfide (CaS) precipitation in spent acid containing H2S scavengers. This precipitation has been observed when low scavenger concentrations were used in spent hydrochloric (HCl) acid. This paper provides optimum design parameters that allow for much effective use of H2S scavengers without causing the formation of calcium sulfide scale.
Design of Sucker Rod Pumping Systems for Effectively Handling Solids and Sand
Authors: Ghareeb Mohamed , Beck Anthony (Tony)
Published: May 2012

Subsurface pumps in sandy wells suffer mostly from abrasion of Sand (quartz). To prevent the pump from being stuck by sand grains and to reduce pump part failures due to sand, it requires understanding of sand problems and how they damage pump parts and cause stuck pumps. This can help with the design of the pump configuration in order to improve pump inherent reliability in sandy well conditions. Usually the common types of sand problems are Plunger sticking in barrelPump sticking in tubing (insert pumps)Sand damage to barrel, plunger and valvesSand packing off in the pumpSticking valves

The subsurface pump equipped with a sand screen and additional modifications worked out over the years with different oil producers have helped it become one of the best solutions for difficult sand laden wells. Where some sucker rod pumps and some exclusion devices are designed to keep solids from entering the pump. Certain pump configurations help in handling sand in terms of moving the sand through the pump with a minimum of wear.

This paper will discusses the main concepts in sand handling with highlighting some exclusion devices, and the most practical solutions for best sand handling pump and completion design as a function of conditions
Acidizing Sandstone Reservoirs Using HF and Organic Acids
Authors: Yang F.. , Nasr-El-Din H. A. , Al-Harbi B..
Published: May 2012

Mud acid, which is composed of HCl and HF, is commonly used to remove the formation damage in sandstone reservoirs. However, many problems are associated with HCl acid, especially at high temperatures. To overcome many of these drawbacks, organic-HF acids have been used as an alternative to mud acid. However, very limited research has been performed to reveal the reactions between organic-HF acids and minerals in sandstone reservoirs.

In this study, formic-HF and acetic-HF acids were examined to react with various clay minerals (kaolinite, chlorite, and illite), in comparison with mud acid. A series of acid mixtures with different ratios and concentrations were tested. Inductively coupled plasma (ICP), scanning electron microscopy (SEM) and 19F nuclear magnetic resonance (NMR) were employed to follow the reaction kinetics and products. Core flood experiments on sandstone cores featured with different mineralogy, with dimensions of 1.5 in. × 6 in. were also conducted at a flow rate of 5 cm3/min. The core effluent samples were analyzed to determine concentrations of Ca, Mg, Fe, Si, and Al by ICP.

Both formic-HF and acetic-HF acids are much milder than mud acid. The species and amounts of reaction products of different clay minerals in organic-HF acids depend on mineral type, acid composition, and ratio. This conclusion is further confirmed by core flood experiments, in which sandstone cores with different mineral compositions give quite different responses to the same acid mixture. This paper will discuss the detailed chemical reactions that occurred within cores and were followed by chemical analysis of core effluent samples.
Virtual Flow Meter pilot: based on Data Validation and Reconciliation Approach
Authors: Haouche Mohamed , Tessier Adrien , Deffous Younes , Authier Jean-Francois
Published: May 2012

To face the new challenges of production metering and back allocation, TOTAL is making an important effort to develop and test new approaches to improve its current production metering systems particularly for multiphase conditions. New technologies are tested through pilot applications within different subsidiaries worldwide. Thanks to these pilots, the suitability of various approaches to the needs of each asset can be analyzed and tested in detail.

The SPE-149908 (M. Haouche 2012) paper presented a Virtual Flow Meter (VFM) field pilot in Qatar. The approach used on this VFM is the Data Validation and Reconciliation (DVR). The single Well model of the VFM is an assembly of three main units: Reservoir unit, Electrical Submersible Pump (ESP) unit and Production Tubing unit. The conclusion was that the VFM was catching-up the production trends of all the Wells of the pilot. However, the VFM results are not quantitatively comparable to the production measurements, especially when the VFM is running far away from the calibration period. A recommendation was to enhance the ESP model that controls mainly the information on the flow rate.

The present paper describes a new method for modeling the ESP performances in the VFM. This method takes into account the impact of the Gas on the ESP performances. Results are presented for three operational cases to see the benefits of this method and where it is applicable. The ESP operational data have been considered for a long time period in order to get a representative range of operational conditions. Conclusions are made on the capabilities of the new method to assess the impact of Gas on the ESP operational performances.
Core Flood Study of a New Emulsified Acid with Reservoir Cores
Authors: Sayed M. A. , Zakaria A. S. , Nasr-El-Din H. A. , Holt S.. , Al-Malki H..
Published: May 2012

The main objective of well stimulation has been to create wormholes or fractures in order to bypass the damaged zone and enhance the permeability in the near-wellbore area. Regular HCl was the main stimulation fluid. However, at high temperatures, both reaction and corrosion rates become very high and regular HCl loses its advantages. There are many alternatives for regular HCl; emulsified acid is one of the available alternatives for regular HCl.

In the present work, an emulsified acid system was used formulated using a cationic surfactant. This system was tested using reservoir cores obtained from a carbonate reservoir. The core samples were analyzed using CAT scan to study the presences of vugs or channels, and to determine the presence of anhydrite. Small samples of the cores were analyzed using the SEM technique. A series of core flood tests were conducted using 15 wt% HCl emulsified acid systems formulated using 1.0 vol% emulsifier. The acid volume fraction was 0.7, and all experiments were performed at temperature of 220°F. The acid injection rate ranged from 1.0 to 10 cm3/min. After acid treatment is accomplished, the cores were CAT scanned to study the number and distribution of wormholes. Samples of the effluent fluid were collected during the core flooding experiment. These collected samples were analyzed using the ICP, to determine the calcium and magnesium concentrations.

The CAT scan of the cores obtained from a carbonate reservoir showed a great heterogeneity. The static test for solubility of rocks in regular 15 wt% HCl, indicated that the rocks has a high solubility in acid and the need to use an effective retarded acid system. From the coreflood study, there is an optimum injection rate for an emulsified acid system when it was tested reservoir cores, and it was found to be in the range from 5 to 7 cm3/min. The emulsified acid system can be used effectively, with no face dissolution, at low and high injection rates. For high permeability cores, the final permeability enhancement (ratio of final to initial permeability) increased with increasing the injection rate.
The Effect of Viscoelastic Surfactants and a Mutual Solvent on the Wettability of a Carbonate Rock
Authors: Adejare O. O. , Nasralla R. A. , Nasr-El-Din H. A.
Published: May 2012

Proper acid placement/diversion is required to make matrix acid treatments successful. Viscoelastic surfactants (VES) are used as diverting agents in carbonate matrix acidizing. However, these surfactants can adversely affect wettability around the wellbore.

Spreading droplets may not reflect wettability, if they result from low oil-acid IFT's. Therefore, a procedure was proposed for contact angle measurements when surfactant solutions, such as spent acid with VES and EGMBE,reduce interfacial tensions (IFT's) and cause oil droplets to spread (Adejare et al. 2012).

The effect of two amphoteric amine-oxide VES', designated as "A" and "B", and an EGMBE preflush and postflush on the wettability of Austin cream chalk was studied using the proposed procedure.In addition, the two-phase titration experiment was used to measure VES adsorption.

A treating schedule sequence typical of carbonate matrix acidizing was used. Rocks were centrifuged in fluids representing the preflush, main acid stage, diverting stage, and postflush.The difference in contact angles before and after centrifuging shows the effect of surfactants in the spent acid on wettability.Contact angles were measured in spent acid with HCl only to prevent VES and EGMBE from reducing IFT's.

VES "A" and "B" adsorb on the rock surface at 25 and 80°C.Experiments with acid treatments with 4 vol% VES "A" and "B" diversion stages and a 10 vol% EGMBE preflush and postflush made initially oil-wet rocks water-wet at 25°C, 80°C, and 110°C. Acid treatments with a 4 vol% VES "A" diversion stage only made rocks water-wet at 25°C and 80°C. For the parameters investigated, our results suggest that diversion with VES "A" only, andan EGMBE flush following diversion with VES "A" and "B",can alter wettability to water-wet and increasethe relative permeability to oil.
Reliable & Efficient Feed Gas Preparation - A Key Enabler to Pearl GTL
Authors: Ramachandran Sakthivel , Engel Dico
Published: May 2012

In July 2006 the first stone was laid for constructing the largest Gas To Liquids (GTL) plant in the world, the Pearl GTL Complex in Ras Laffan, Qatar. After completing Shell's first GTL plant in Bintulu, Malaysia in 1993 with a debottlenecked capacity of 14 kbbl/d, the Pearl GTL plant is a major leap forward in size, innovation and integration. Pearl GTL is designed to produce 140 kbbl/d of finished GTL products and some 120 kbbl/d of natural gas liquids, including field condensate and ethane. Raw feed gas is routed from 2 identical offshore Platforms in the Qatar North Field via 2 parallel 30" subsea pipelines to the onshore GTL manufacturing complex.

The reliable, efficient and well integrated Feed Gas Preparation plant is a key enabler to the overall success of the Pearl GTL complex. Feed Gas Preparation includes offshore platforms, inlet receiving facilities, integrated gas treating units and NGL extraction/fractionation unit.

The design of the Feed Gas Preparation complex is based on Shell's years of experience in designing, building, licensing and operating many Gas Processing & LNG plants. Due to the highly integrated design, implementation of significant technology innovations was executed only after thorough analysis and issuing of formal development releases.

The Pearl GTL plant came into operation on 23rd March 2011. Stable production of sweet Natural Gas, Sulphur, Propane, Butane and Condensate at 40% design capacity was achieved within 10 days. The plant is meeting its design capacity and product quality, and complies with stringent environmental specifications. The innovative design approach used has resulted in a stable, reliable operation and has contributed to the sustainable development of the project.

This paper describes in detail the configuration of the Feed Gas Preparation plant in Pearl GTL and highlights the key features in the design, construction, commissioning and start-up experiences.