bluuebunny/crossref_metadata_2025 huggingface dataset:
Exceptional Management and Optimization for Intelligently Controlled Wells using Smart Surveillance and Diagnostics in Joint Operations - Wafra Field
Authors: Babahani B.. , Spain John , Bhat M. S. , Heshmat K.. , Assem A.. , Mohammed Z..
Published: October 2015

Instrumentation on around 900 artificial-lift system (ALS) wells in the Wafra field allowed remote monitoring, control, and analysis for exceptional management. Having software capable of controlling wells, gathering real-time data, and integration with any database, created another level of effective surveillance. Using real-time optimization simulation software, helped in identifying opportunities, selecting candidates, tracking well behavior, reducing action response duration, reducing number of failures, and saving power cost. This manuscript focuses on the optimization implementation and results verification.

The field development team is divided by reservoir type wherein each engineer is responsible for a set of wells. The wells are artificially lifted using different types of pumps including sucker rod pumps' (SRP), electrical submersible pumps (ESP) and progressive cavity pumps (PCP). The manual process of collecting data is progressively becoming replaced by high tech well instrumentation, which is connected to a private network cloud reaching engineer's desktops. This process has created a collaborative environment consisting of different teams such as asset management and operations engaged in production optimization utilizing the smart software modules. The changes to the well are tracked and diagnosed instantly.

Deploying the digital oil field allowed engineers to instantly access well data which has improved the management process of identifying well issues based on pre-configured and intelligent alarms. It has created short- and long-term plans for production optimization taking into consideration the health and performance of wells and equipment installed in the field. The aim has been to reach and maintain the optimal rate for each well.

Case studies conducted include: – Candidate wells for chemical injection based on measuring the difference in flow line pressure from temperature change – Unbalanced rod pump wells identified based on the comparison between the measured and calculated counter balance torque – Wells with gas interference were highlighted based on continuous dynacard collection – Wells with motor overload were diagnosed based on real-time data comparison between the nominal and actual output current – Production increase opportunities were identified based on the diagnostics report and analysis report created from the software optimization module

Smart field optimization has been implemented for the first time in the instrumented artificially lifted wells in a partitioned neutral zone between Kuwait and Saudi Arabia, whereby the data is being accessed from admin camp, which is an office area outside the field. It has enhanced the collaborative environment between the different teams working in a joint venture allowing engineers to be focused on solving well problems instead of data collection and validation procedures.
Flare Gas Recovery Using Innovative Unconventional Technology, Avoiding the use of Compressors
Authors: Peeran Syed M , Beg N..
Published: October 2015

Legislation, the environment, economic and corporate social responsibility are some of the key factors that are governing the recovery of flared gas worldwide. There is growing awareness of the issues associated with flaring and efforts are being made globally by operators and governments to minimise it. There are several technologies for reducing flaring at source or in a processing plant. The choice of technology depends on the economics of the project, frequency of flaring, infrastructure available and location of the producing facility. This paper covers innovative Flare Gas Recovery Systems using Surface jet Pumps and avoiding the use of compressors.

Conventional Flare gas Recovery systems usually comprise of one or more compressors, which compress the collected flare gas and route it for further processing. The compressor design is critical and determines the system's capacity and turndown capability. However compressor based solutions can be quite large, complex and have high capital and operating costs. They are also very sensitive to changes in gas composition and MW.

Surface jet pumps (SJPs) are simple, low cost passive devices that can also be used to recover flare gas. They use a high pressure (HP) fluid as the motive force to boost the pressure of the LP or LLP flare gas and deliver it for processing. The high pressure fluid that is needed as the source of energy or motive flow is usually gas taken from the discharge of a compressor or from the export gas line. However HP liquids, such as oil or injection water can also be used. Advantages of using SJPs include low cost, no moving parts, zero maintenance, zero power or fuel gas usage, small footprint and varying layout configurations. SJPs are well suited to liquid ingestion and to changes in process conditions (without affecting performance).

This paper discusses the use of Surface Jet Pumps as an alternative to compressors for flare gas recovery and cites several case studies of where this technology has been successfully utilised. The design and operational criteria of SJPs, as well as the economics is also highlighted.
Increase in Sand Production Used as an Indication for the Next Steam Injection Period in Heavy Oil Wells
Authors: Quttainah R , Al Besari Ghazi , Mehmood F , Hossam Mesbah , Dange A
Published: October 2015

In rod pump applications around the world heavy oil and sand production is believed to be a dangerous combination. This paper highlights a case study of a heavy oil well in the North Kuwait field where sand production was monitored closely to avoid flow line choke and down hole failures. This case study was used as a pilot for the neighboring wells producing from the same reservoir. In case of wells producing heavy oil with considerable sand production and that undergo cyclic steam stimulation the challenge is often at the end of the production cycle. While the oil is thin and has good viscosity the sand settles itself at the bottom. However, with time as the oil gets colder and thereby heavier, it carries the sand along with it to the surface causing plug in the flow line. This is due to the high viscosity of the oil. This is believed to be the end of production period beyond which it would have been impossible to produce any further even after sand cleanup. Certain operational procedures were established to ensure the integrity of the down-hole equipment and to avoid the failures. It has been observed that by effective sand monitoring it was possible to determine the next injection cycle with more precision. This standardized the injection and production cycle. The flow line choke up problems were completely eliminated as the production period would cease as soon as some sand would begin to appear at the surface. It was possible to establish API gravity cutoff for oil production thus avoiding rod and pump failures. This implementation has been undertaken for the entire field and has shown significant operational efficiency. A pilot was conducted to justify the use of sand production as an indication for the next production cycle for heavy oil well under cyclic steam stimulation.
Field Scale Gas Injection Efficiency Optimization Based On Combined Analysis of Finite Difference and Streamline Simulation
Authors: Algdamsi Hossein Ali , Amtereg A. A. , Agnia A..
Published: October 2015

Within the framework of reservoir management streamline simulation finds one of its typical applications as one of the effective tool to improve gasflood and pressure maintance performance. Streamlines provide an instantaneous visualization of flow patterns as a function of reservoir heterogeneity. Additionally they also provide an estimation of the well allocation factors (WAFs) between injection and producing wells. Such information is a default outcome from streamline models but not from finite difference simulation and it is particularly useful in optimizing and balancing well patterns and field scale injection rates. However finite difference simulation has the advantage of implicitly taking into account all the details of an existing simulation model, especially advanced well management strategy. In this paper we demonstrate a straightforward workflow for optimizing injection rate based on a comprehensive analysis of two key parameters: injector efficiency (IE) metric and WAFs. The optimization approach consists of a three step procedure starting with streamline analysis using commercial software which combines the power of finite difference simulators and streamline technology to derive streamlines from the flux field generated by the finite difference simulation that represent a snapshot of the flow pattern within the reservoir, well drainage region information and fluid allocation changes with the flood progression. Second using a simple analytical calculation to compute weighting factors for injection/production rate targets from a derived ranking of the wells (IE). Finally reallocation of injected fluid volumes from low-efficiency to high-efficiency injectors improves volumetric displacement and sweep efficiency in the less swept areas of the reservoir. The application of this workflow is demonstrated with a real-field example of an onshore tight sandstone reservoir where the pattern balancing has led to incremental production of 3.5 % over the 5 year forecast in which the IE average of the field is the benchmark for whether more or less injection volumes were required while obeying facility constraints.
Successful First Application of Flow-Channel Hydraulic Fracturing Technology in Kuwait Accelerates Development of Marginal Reservoirs
Authors: Anthony E.. , Al-mosaileekh S. R. , Al-Othman M.. , Alhouti N. B. , Abdel-Basset M.. , Mokhtar A.. , Sheikh B..
Published: October 2015

In a high-perm/strong-aquifer environment, comparatively low-perm/heavy-oil/solution-gas-drive reservoirs inevitably get sidelined. Flow-Channel Hydraulic Fracturing, however, with infinite conductive channels for fluid flow rather than intra-granular flow, as in conventional fracturing techniques, offers a tangible solution for increased productivity. The channels in the proppant pack are created through a patented technique that combines special pumping protocol, perforation scheme, fracturing fluid design and fiber technology. These conductive channels accelerate fracture cleanup, and achieve longer effective fracture half-lengths, thereby enhancing productivity, injectivity& recovery.

In North Kuwait, 90% of wells drilled are vertical, penetrating a wide range of reservoir types consisting of high and low permeability sandstones and carbonates, with varying crude types from medium heavy to condensate. Flow-Channel Hydraulic Fracturing technology, with its infinite conductive flow-channels and reduced risk of premature screen-outs, was selected as the optimum stimulation technology for the most challenging low-permeability/low API gravity candidates where conventional stimulation techniques are not providing the aimed results. Conventional propped hydro-frac treatments were attempted previously with marginal benefit and operational failures. This was the first application of this technology in Kuwait.

Multi-disciplinary candidate screening and selection for the initial pilot wells, followed by pre-job logistics and operational planning with the service provider, resulted in a flawless execution with text-book results.

Post-job production results showed a stabilized flow rates with more than 85% production gain compared to the flow rates expected from conventional completion techniques. Incremental production paid out stimulation expenses in 35 days.

This very successful introduction for Flow-Channel Fracturing application opened up opportunities in low API reservoirs where even the flow through the proppant pack from conventional fracture stimulations is limited. Injectors associated with IOR & EOR projects, and Carbonate completions traditionally responding to repeated periodic acid fracture stimulation, may require only single channel proppant fracture during their life cycle.
PCP Redesign and Analysis Involving Pump Watcher System
Authors: Quttainah R. B. , Mahmood F.. , Bhat M.. , Mantilla O.. , Imbrea R..
Published: October 2015

Progressive cavity pumps (PCP) were introduced in Kuwait Oil Company (KOC) fields for the first time in year 2012 whereby 100 wells were to be awarded for a period of 5 years. Over a 3 year period over 50 pump installations were carried out. Due to the growth of the project the operations strategy focused on implementation of certain tools to aid in analysis and optimization of the wells thus improving the run life. Pump Watcher system is a part of a lease contract that involves PCP rental developed by KOC. The contract warrants remote surveillance and control of the pump including but not limited to start/stop and speed change. Although the PCP rental began in the year 2012, real-time monitoring and control was accomplished only in 2014 as the infrastructure related to radio communication was not in place. There has been a paradigm shift in data availability and quality before and after the installation of pumps, variable speed drives (VSDs), and remote monitoring and survey. This manuscript focuses on the benefits achieved ever since downhole gauge data and related pump information was made available on a real-time basis. The manuscript focuses on the following with case studies and examples:

Improved run life Wells working under recommended operational conditions Preventative actions due to real-time data (RTD)
Selection of Suitable Viscosity Reducer to Facilitate Test Production of Heavy Oil and Deep Reservoir
Authors: Ghloum Ebtisam , Rashed Abeer , Al-Jasmi Ahmad , Al-Ali Abdulmuhsen , Mali Prasanna , Sanyal Arunava
Published: October 2015

Exploitation of heavy oil from deep reservoir is often dictated by appropriate selection of viscosity reducer and artificial lift. For the proposed pilot in this study, it is necessary to identify suitable viscosity reducer to produce heavy oil from deep reservoirs, with down-hole electrical submersible pump (ESP). Broad field data of this reservoir are depth of 9300 feet, crude API gravity of 10 and crude viscosity of 10000 centipoise, at 4500 psi of SBHP and at 190 °F of BHT.

The main objective of this study is to evaluate different viscosity reducer chemicals (VRC) for their efficiency in reducing the viscosity under severe reservoir conditions

SARA analysis was carried out on flashed crude oil sample to check the asphaltene stability of samples. Series of viscosity tests were conducted using an electro-magnetic viscometer in order to test performance of different viscosity reducers at diverse temperatures and pressures conditions.

Experimental studies showed that as pressure decreases, viscosity of oil sample decreases with reduction in temperature. However, when the effect of different viscosity reducers on representative oil sample was studied, at 5000 psi and at reservoir temperature of 190 °F, it was noticed that reduction in viscosity of oil sample from 16,230 centipoise to less than 850 centipoise could be achieved.

It is concluded from lab studies that reduction of viscosity of given heavy oil sample can be achieved with the help of suitable viscosity reducer to an extent, wherein, it is possible to operate downhole ESP and produce heavy oil from deep reservoir. Studies can also have practical application as an alternative planned production strategy to exploit such reservoirs. Study results definitely have far reaching influence to decide optimum dosage of viscosity reducer during execution. These studies can be seen as a representative model for performance comparison to test different viscosity reducers under diverse conditions. Studies also emphasized the need for carrying out meaningful lab studies for appropriate selection of viscosity reducers; while planning exploitation of heavy oil and deep reservoirs.
CCS: Experiences in Project Development
Authors: Gray Lily , Maas Wilfried
Published: October 2015

The development of a CO2 value chain for CCS poses a number of decisions relating to the capture technology, storage selection and transportation of CO2. In addition, an appropriate approach to the non-technical aspects and risks needs to be incorporated. This paper will provide an overview of the different options available to projects and discuss the selections that Shell has made in its own CCS project development.

Shell has developed a global portfolio of CCS demonstration projects driven by the recognition that carbon capture and storage is currently the only technology available to mitigate emissions from large scale fossil fuel use. Shell’s projects cover a wide range of technologies and consist of targeted applications that are of relevance to the wider oil and gas industry. The Shell portfolio includes Peterhead, Quest, Technology Centre Mongstad and Gorgon. The development of these projects has demonstrated that there are multiple drivers in the development of a CO2 value chain and these can be very project specific.

In the development of CCS for power plants, one of the key considerations is the ability of power plants to be able to respond flexibly to the normal fluctuating demands of the power market. Therefore, a key driver in technology selection is to limit the impact that the addition of a CCS plant could have on this flexibility. On the other hand, availability may not be the most important factor, because power plants usually use an "end of pipe" CO2 solution, and therefore the unavailability of a post-combustion CCS plant will have minimal technical impact on the power export.

However, for a hydrogen plant where hydrogen demand can be relatively stable e.g. in a refinery, then the capture technology selected will not usually need to follow a varying demand but, because the capture technology could be part of the wider process, it may need to offer high reliability and availability.

Similar considerations need to be made about the dehydration technology and the CO2 compression technology selected. For example, re-use of existing facilities can result in more stringent requirements on CO2 purity and possible pressure limitations that could be designed out in a new facility.

In conclusion, Shell';s experience has shown that development of CCS projects poses some new challenges but through good integration of technology and a structured approach to technical and non-technical risks, these can be overcome for successful project delivery.
Best Environmental Practice Implementation, While Executing Seismic Exploration in Kuwait Offshore
Authors: Minhaj Rifad Ali , Al-Ajmi Bader
Published: October 2015

KOC conducted its first 2D Offshore Seismic Acquisition Survey over the State of Kuwait Offshore covering some of the Environmental Sensitive & restricted areas to explore the hydrocarbon potentials in Offshore Areas. The potential environmental effects, risks and control measures were designed to minimize/mitigate the actual and potential risks of the survey.

This Abstract outlines the industry best environmental Practices adopted during the various stages of the project for executing the Seismic Survey in the State of Kuwait Offshore Environment.

The project was first of kind in KOC using fleet of 12 Vessels for carrying out the Seismic Acquisition Survey Operations in the State of Kuwait Offshore and it faced many challenges during the different phases of the project. Various Methods, Procedures & Processes were followed to overcome these challenges by identifying & implementing industry best HSE standards in terms of Geophysical offshore Surveys, Implementing KOC’s HSE Management System Elements, Conducting a detailed Environmental Impact Assessment Study on the survey area, in identifying environmental aspects & identification, Waste management with respect to both national & International waste regulatory requirement in operating offshore.

The project was well planned & properly executed by identifying potential environmental and socio-economic impacts associated with the preparation, operation and abandonment regarding 2D marine seismic activities in the State of Kuwait offshore area, by identifying the Environmental Sensitive areas such as breeding grounds and shallow coral reefs located in the prospect area, it avoid the Acoustic disturbance, especially from Seismic High Pressure Guns on Marine Mammals etc. by following Joint Nature Conservation Committee guidelines for minimizing the risk of injury and disturbance to marine mammals from seismic surveys, the project followed soft start procedure for minimizing the risk of injury to marine mammals, an Offshore Mine Mitigation Measures and Information plan has been prepared to identify and take necessary actions on the possible EODs that may be present in offshore environment, initial hazard survey was carried out to identify significant gradients fishing areas and seafloor features. This helped to avoid and reduce the probability of disturbing the major fishing areas and hazards to specific bottom features.

In spite of many challenges encountered during the different phases of the project, the overall project performance remains @ more than Two Million LTI free Operations with Zero Environmental Incidents.

This paper can give the guidance/benchmark towards the best practices to be followed in terms of HSE for executing any future offshore projects in the State of Kuwait Waters. Investments in these Best Practices for seismic exploration results in fewer impacts and good stakeholder relations for later phases of exploration.
Five Years Journey of Advanced Completions in KOC
Authors: Siddiqui Mohammed A. , Al-Jasmi Ahmad K. , Al- Rasheedi Menwer M. , Al-Abdullah Hashem F.
Published: October 2015

With an objective to increase the production to 4.0 MM BOPD, Kuwait Oil Company is developing its fields with optimum technology solution. Technological innovations in E&P sector are on growing trend, based on which, KOC included "Realize the value from Technology" in the frame of its strategic objectives. The Key Performance Measure (KPM) of this objective is to adopt new technologies at a scale that ideally addresses the identified challenges. In view of this objective and associated KPM, it was decided to implement the advanced completion technologies in various reservoirs of the Company.

KOC has several prolific reservoirs spread all over Kuwait. These reservoirs have mild to severe differences in rock properties and fluid characteristics. Burgan is the major Cretaceous sandstone structure extended all over the Kuwait with varied properties. The permeability of Burgan in general is in multiple Darcy. Its fluid viscosity in NK and SEK is low, in the range of 0.5–3 cP, while in WK it is 28–30cP. Minagish Oolite in West and Maududd in North are major carbonate reservoirs with varying rock and fluid properties. Horizontal wells are considered superior over conventional vertical wells due to augmented production through increased reservoir contact. However, these wells pose severe production challenges due to variations in permeability, reservoir pressure as well as frictional pressure drop along horizontal length. Hence, equalizing inflow, delay water breakthrough, minimizing heel-to-toe effects and maximizing the ultimate recovery are the primary challenges to be addressed to gain advantages of horizontal wells.

One of the promising technologies to address these challenges is the advanced completions: inflow control device (ICD) and Interval control valves (ICV). The campaign of application of advanced completions in KOC was started in 2009 under the umbrella of R&T. The completions include various types of ICVs and ICDs. The latter includes passive ICD, Advanced ICD with sliding sleeve, Autonomous ICD without moving parts and ICD with stimulation port. The technology application was based on its value addition and Company‘s commercial group policies, while maintaining the technical superiority. The technology was trialed successfully in series in various fields and reservoirs through best practices and multi-disciplinary team approach. The focus was made to avoid drawbacks in pilot stage to avoid disapproval of the technology by management. Application of this technology led to multifold increase in sustained production in horizontal wells in all reservoirs and simultaneous reduction in water cut.

This paper covers the results of the advanced completion pilots, application methodology & novel practices and selection criteria that ultimately led to tremendous increase in production and full-scale field implementation of the technology.
Smoke Free Testing Solution in Sour Heavy Oil Wells Protects Environment and Gains Production
Authors: Abdulrahman Khalid , Ibrahim Anwar , Acar Cagdas , Elgendi Mostafa , Abdellatif Mohammed
Published: October 2015

Umm Niqa field has heavy oil reserves in the shallow sandstone reservoir located in Northern Kuwait (NK) is probably the one of the important accumulation of heavy oil (μ > 100 cP). Although a small resource in comparison to Canadian and Venezuelan heavy oil resource, these heavy oil reserves nonetheless represents a significant fraction of Kuwaiti resources1. Kuwait Oil Company (KOC) is aiming to develop and produce from this heavy oil reservoir with the latest technologies and methodologies in a safe and environmentally friendly way.

One of the important issue to reach KOCs overall company objective is to protect the environment of Kuwait by eliminating the effect of hydrocarbon burning from oil exploration operations which causes many forms of pollution, noise, toxic gases, soot, acid rain and carbon dioxide emissions. The high H2S content found in the reservoir increases the complexity of the operation and creates a dilemma over operational safety versus environmental concerns. KOC and Schlumberger has been developing strategies to reduce burning of oil having high Hydrogen Sulfide (H2S) concentrations during well clean-up and well testing operations. The ultimate aim is to test the wells with zero flaring, which will also enable significant production gain by immediate flow of hydrocarbon to production. The developed methodology for testing of the sour heavy wells with zero burning of oil consist mainly: Efficient separation of the gas from oil, burning the separated gas separated and scavenging the oil from the remaining H2S afterwards, sending the scavenged oil to storage tanks and transfer it to the production facility. This methodology has been applied successfully in two heavy oil wells resulting over 6000 bbl of production gain and preventing emissions that could have arisen from that amount oil burning. This paper explains the methodology applied to cleanup and well testing operations in two wells from a sour heavy oil reservoir and the results obtained by application of the methodology in details.
Talent Gap: A Golden Opportunity for the GCC Oil Industry
Authors: Dutto Paolo Roberto , Sterli Laura , Schwarz Jacqueline
Published: October 2015

The release of talented PetroTechnical Professionals caused by the significant Oil price volatility represents a tremendous opportunity for the GCC Oil Industry to rejuvenate its demographics and close its historical Talent Gap (albeit still leveraging Expats) to nurture the future generation of Local resources.

The Talent Gap represents the gap between the ideal demographic distribution and the current and future expected availability of PTPs, with impacts on the delivery capabilities across the Oil Industry lifecycle.

To face the complexity of the Talent Gap challenges, it is necessary to leverage a full suite of approaches / tools based on field project experiences, listed as follows: –HR Strategic Planning;–Nationalisation of Resources;–Professional Roles;–Enhanced Competence Development;–First Line Leaders;–Manpower Contingency Plan;–Asset Competence Rebalancing.

Such tools are selected and combined based on a Company specific diagnostic approach taking into consideration its internal current situation and future strategic challenges, together with the changing Industry scenarios.

As far as the Middle East is concerned, the Talent Gap issue is more severe compared to the average of the Industry, as it has been present for a longer period mostly due to NOCs progressive change in their role from petroleum resource owners to active operators.

The current Oil volatility may prove to be a huge opportunity for the Middle East players allowing them to cover the Talent Gap by hiring resources on the down-slope, since the Middle East NOCs are the least affected by the low price of Oil.
Vapour/Gas Cloud Tracking System
Authors: Paul Isaac , Samdani Deepak
Published: October 2015

Objective

Present the emerging technology in Gas Detection and Cloud Tracking and how it offers more robust monitoring of the assets when used in combination with the conventional gas detection system. Bring out the deficiencies in the present Gas detection and monitoring systems and how this new technology complements the existing technologies.
Typical Process Challenges and Configurations for Sour Gas Mega Projects
Authors: Nick Amott , Stephen Mogose
Published: October 2015

The last decade has seen the initiation, start-up and ongoing development for major oil and gas production projects requiring processing of extremely sour gas. Projects in the UAE and CIS states (particularly Central Asia) require processing of well fluids containing up to 10 mole % CO2 and 23 mole % H2S, with the potential for future projects to see the H2S level increase further. These projects are being designed to treat and process flows of up to 1,000 MMscfd alongside production of oil and/or condensate, as well as NGL/LPG recovery. The world scale processing of sour gas leads to the largest ever sulphur plants installed, with total plant capacities up to 10,000 TPD of elemental sulphur. Kuwait with the Jurassic gas projects is embarking on major sour gas processing and is ideally placed to benefit from the experience and strategies developed in these mega projects.

This paper summarizes a selection of the key sour gas mega project metrics and outlines some of the areas where the very high H2S and organic sulphur content of the well fluid, and the high ambient temperatures, either impacted the design of the process units or required additional design features. The technical discussion in this paper uses information gained from Fluor's experiences on several sour mega projects and covers: Inlet gas conditioning to ensure there is no hydrocarbon condensation during the gas treating stepRemoval of H2S, CO2, COS, and mercaptans from the gas phaseCondensate/oil treating options for organic sulphur removalThe design of the world's largest Sulphur Recovery and Tail Gas Treating trains
Injectivity Loss in Polymer Floods: Causes, Preventions and Mitigations
Authors: Glasbergen Gerard , Wever Diego , Keijzer Efraim , Farajzadeh Rouhi
Published: October 2015

Polymer flooding is an attractive option in hydrocarbon maturation plans. Several successful polymer floods and pilots have been implemented. One of the risks in polymer flooding is loss of injectivity. The consequences of loss of injectivity can be large. In conditions where matrix injection is required, reduction of injection rate may result in a much slower propagating polymer front and consequently later arrival of the anticipated oil bank eroding on the economic value of the EOR process. In extreme cases it can even lead to loss of the injector. Under fracturing conditions the loss of injectivity may be less noticeable, but it can lead to out of zone fracturing or fractures that grow too much in size and cause shortcuts to the producers or affect future infill well drilling.

Reduction of injectivity is a generic concern in conventional waterfloods and can play an even larger factor when adding polymer to the waterflood. The increased viscosity of the injected polymer solution is the most obvious reason for an anticipated decrease in injectivity, but also other mechanisms can have an impact. These mechanisms include excessive polymer adsorption and associated permeability reduction, filtration of impurities in the polymer solution, fluid incompatibilities or reduced water quality.

In this paper we will discuss the various causes for loss of injectivity and propose a structured approach for the associated prevention and mitigation options. Prevention includes (1) selection of the most appropriate polymer type; (2) best practices for preparation of the polymer solution; (3) safeguarding the water quality; and (4) enabling options for mitigation in case excessive injectivity loss is observed. The remediation step includes (1) the identification of the root-cause of an apparent injectivity problem; (2) the design of an appropriate clean-up treatment; (3) monitoring of the operation; and (4) implement measures to avoid repetition of the problem. We will include an overview of the preventive and mitigation options for the different causes of injectivity decline in polymer floods.
Unique Application of a Cementing Stage Tool with an Open Hole Multistage Completion System in Saudi Arabia
Authors: Siham Ahmed , Gardiner Colin , Wilson Stuart , Mueller Mitchell
Published: October 2015

Stage tools have been commonly used in North America for monobore completions to optimize economics. By cementing back the vertical and build sections of the wellbore, the requirement of the intermediate casing and liner hanger packer can be eliminated. An operator working in the K-1 carbonate formations of a massive field in eastern Saudi Arabia was examining a unique application of a stage tool to effectively cement and isolate a water-producing build section of a sidetracked lateral wellbore. The well incorporated a liner hanger packer with a multistage completion system. This paper will describe the distinct operational challenges encountered and how they were solved by redesigning an existing stage tool.

The well profile and construction specified that the liner had to be hung above the sidetrack point. Therefore, it was critical that the sequential operation of running the lower completion string, setting the liner hanger, releasing the liner hanger running tool, setting the open hole packers, cementing the upper liner section and then setting the top packer be completed with tremendous accuracy for a successful job. The operator selected a stage tool with a secondary contingency closure mechanism that did not limit the inside diameter through the system. This mechanism would ensure that all stages could still be stimulated if the secondary closure option was required. The use of the stage tool with a liner hanger system required some design modifications; the typical single foam plug, used to displace cement and close the tool in the standard version of the stage tool, was not an option. Instead, the operator required that a separate drill pipe dart and wiper plug assembly be used to displace cement through the drill pipe and the liner. The stage tool was, therefore, redesigned to close with a wiper plug launched from below the liner hanger packer.

After open hole conditioning, reaming and logging, the lower completion was run to setting depth and all equipment functioned without any issues. The problematic water producing zone was cemented and isolated and the stage tool was closed without the need to use the secondary closure mechanism. The stage tool was then milled out, leaving the well ready for stimulation. The redesigned tool enabled the operator to effectively cement the upper wellbore with no inside diameter restriction for stimulation.

This paper highlights the first introduction of cementing stage tool technology in conjunction with a multistage completion system to an operator in Saudi Arabia and the tool redesign required for accommodating a liner hanger packer in the wellbore. This method could also be applied to any type of lower completion such as sand management screens, inflow control devices or in conjunction with slotted or solid liners as an off-bottom cementing application.
National Oil Companies; Digital Oil Field Technology Transforming Closed & Obsolete Well to a 100% Oil Gain Value Proposition
Authors: Jamal Mariam Abdul-Raheem , Chetri Hom , Nair Sajan , Al-Subaiei Dalal Salman , Al-Zaabi Hamad Ahmad
Published: October 2015

By using Persistent and Daily Digital Oil Field Diagnostics techniques a KOC FD team transformed a 5 year closed well, into a 2000 mdb Oil Gain with a remarkable 0% water cut also been achieved.

Historically wells completed in Complex & heterogeneous carbonate reservoirs always surprised the NOC NK FD team with distinctive behavior and anomalies, noting also that the NOC's North Kuwait field is on the threshold of embarking upon a strategic ambitious water flood expansion and a systematic increase in injection volumes.

Within this process of increasing WI volumes the team realized that it is essential that producing wells are continuously analyzed with the latest Digital Field dynamic data and tangible decisions are made to manage the Voidage-Replacement Ratio. It was during this review process that Well-M was recognized to have a potential added value opportunity

This paper outlines both DOF technical review and management process's used in transforming what was seen as a DEAD and closed well into a daily valuable contributor to the NK asset and assist KOC meeting its production goals.

The paper closes in lessons learned and the next steps to embed this process into KOC's management processes.
Asset Integrity Enhancement Achieved by Integration of On Line Corrosion Monitoring Findings and On Stream Inspection Techniques
Authors: Al-Sulaiman Saleh , Al-Shammari Abdul Razzaq , Jaragh Amer , Khuraibu Yousef , Srinivasan Balasundar
Published: October 2015

Systematic internal corrosion monitoring, fluid analysis and on-stream inspection of process vessels and associated piping in operating plants at appropriate locations can provide valuable insight into the corrosion status and fitness level of the equipment and components. At the Kuwait Oil Company (KOC), Internal Corrosion Monitoring activities and on stream inspection activities are carried out in all their facilities which consists of 22 Crude Processing Plants (or Gathering Centers), 4 Gas Processing Plants (or Booster Stations); 2 Effluent Water Disposal Plants, Seawater Treatment and Injection Plant, a vast network of pipelines carrying different products, as well as Early Production Facilities.

Internal corrosion monitoring is conducted with online monitoring equipment that include corrosion coupons, corrosion probes, bio probes, hydrogen patch probes etc. installed at key locations. Fluid analyses activities are also carried out for different processes to determine various key parameters such as pH, conductivity, total dissolved solids (TDS), total hardness, dissolved oxygen content, hydrogen sulfide (H2S) and carbon dioxide (CO2) concentrations, corrosion and scale inhibitor residuals, Iron (Fe) content (total and dissolved), bacterial activity, etc.Corrosion data and fluid characteristics are analyzed for trends and appropriate recommendations issued to asset owners for corrective, preventive measures to mitigate corrosion and also to advise Inspection requirements based on findings.

On stream inspection activities include visual inspection and non-destructive testing (NDT) inspections using ultrasonic scanning by Automated Ultra-sonic Test (AUT) method and thickness verification of susceptible portions of piping circuits, equipment and related components in the system.

This paper highlights the significance of integrating the on line corrosion monitoring data and on stream inspection data resulting in proactive inspection intervention, repair and replacement of related piping and piping components in effluent water (EFW) system in one of the crude processing plant. Unscheduled plant shutdown and safety incidents were avoided due to proactive action. Further, it helped the company to initiate MOC process to implement proactive measures in similar piping systems at other facilities also.
Oil & Gas Contracts' Risks Negotiation in the Climate of Economic Recession
Authors: Abou-elkhair Gamal
Published: October 2015

For over a century and a half, oil has brought out both the best and Worst of our civilisation. It has been both boon and burden. Energy is the basis of our industrial society. Oil is the world's biggest and most pervasive business, the greatest of the Great industries that arose in the last decades of the nineteenth century. The demand for energy and petrochemicals correlates closely with general economic growth rates. The occurrence of recessions or other periods of low or negative economic growth will typically have a direct adverse impact on our results. Other factors that affect general economic conditions in the world or in a major region, such as changes in population growth rates or periods of civil unrest, also impact the demand for energy and petrochemicals.
Information Management System to Improve Decision Making Efficiency
Authors: Alfajri I.. , Ali A.. , Al-Zaid N. N.
Published: October 2015

With strategic target to produce 200 MBOEPD and become operator of 20% of the daily production asset by 2030, KUFPEC conducted several internal transformation initiatives to achieve them. One of them was the decision to build integrated corporate Information Management System (IMS) for Exploration and Production (E&P) data to improved decision-making efficiency. The paper will explain the strategy, reason and technology used to implement the system. It will also provide benefits and lesson learned from the implementation.

Prior information management system, the company relied on manual process and shared folder. This led to inconsistency among asset teams within the company. It also consumed technical resources time to manage the data and create report for management. Integrated information management system was new in the company. Building information management system from a scratch was a challenging task and could take a significant amount of time. It required strategic approach that allow the company to reap the benefit earlier. Therefore, the company selected to implement information management system for production data first. Production data was among main driving factor for decision-making because the company was mainly involved as non-operating partner.

The company selected ProSource as the solution for integrated corporate information management system. The solution footprint covered most of E&P domains data. It allowed the company to expand the corporate information management system to other domain later. As part of change management, the company created a new Technical Support Department that will oversee the integrated corporate information management system in the company.

During project implementation phase, the support and commitment from the asset teams were high. They supported the project by providing data and active participation in the project. They realized that the project would bring benefit to them and was important for their routine works. The support was very important because they are the owner of the data. They are also the end user of the system once it was implemented.

With the system in place, the production data was stored in a secure and easy to access database. This increase data integrity and confidence of the data. Engineers from different asset team have unified interface to access the production data securely. This reduced learning curve if an engineer was moved to other asset team. It also increased data visibility, accountability and transparency. Production data were available to any body that has permission to access, from engineer to top-level management. Reports were standardized according to the company other initiative. Petroleum Engineers have more time to analyse the data rather than loading and managing the data.

After the benefit realization of information management system for the production data, the company decided to implement information management system to Geology and Geophysics domain later on.
Solvent Enhanced Steam Drive: Experiences from the First Field Pilot in Canada
Authors: Verlaan M. L. , Hedden R.. , Castellanos Díaz O.. , Lastovka V.. , Giraldo Sierra C. A.
Published: October 2015

In recent years, the addition of a hydrocarbon condensate (C4 to C20) to steam operations (such as CSS and SAGD) in heavy oil and bitumen reservoirs has emerged as potential technology to improve not only oil recovery and but also energy efficiency. Shell has extended the idea of solvent addition to a steam drive process, applied it for the first time in the Peace River area in Canada, and obtained evidence of oil uplift in the patterns where solvent was injected. However, piloting this new technology in a brown field had many challenges, especially when evaluating its main economic factors: production increase and solvent recovery.

To overcome these challenges, emphasis was put on experimental design, data acquisition and quality, and production surveillance. The pilot conditions were designed to increase the probability of success on the two economic factors aforementioned within a short period of time. The assessment of the pilot required that all production streams (emulsion and casing vent gas) were metered and frequently sampled to measure their respective compositions. Cross calibration of metered and sampled water cuts was essential in obtaining conclusive production uplift data. Automatic proportional samplers were successfully deployed under these challenging conditions to obtain representative samples. Due to the overlap of solvent and bitumen components, special attention was taken to allocate hydrocarbon production into bitumen and solvent. New in-house developed algorithms were tested to accurately calculate this split.

The addition of a 4 month concentrated slug of solvent in two steam drive patterns resulted in a significant production uplift when compared to two adjacent patterns with steam-only injection. Solvent recovery is still ongoing and exceeds original expectations. Frequent sampling allowed the detection of several trends, including bitumen composition changes during solvent injection and solvent fractionation in the reservoir.
Use of a Salt-Tolerant Friction Reducer Improves Production in Utica Completions
Authors: Rodvelt Gary , Yuyi Silumesii , VanGilder Criss
Published: October 2015

As longer laterals are drilled in the Utica to maximize acreage cover, the stimulation treatments must still establish high pumping rates to effectively treat multiple clusters even within the stages out near the toe area of the lateral. Overcoming this additional pipe friction as well as using various water sources of varying salinity (up to and including 300,000 ppm) with only one friction reducer (FR) polymer product is now possible. An additional benefit of this new salt-tolerant polymer (STP) as the FR additive is its ability to self-degrade with time and temperature to provide significant viscosity reduction for improving well cleanup after the treatment.

This paper discusses use of this new STP to successfully place 131 stages in the Utica on a three-well pad in Ohio using various percentages of brine water with the freshwater supply. This is contrasted with traditional FR and guar used in 61 stages on the same pad and 39 stages on an offset pad. The ability to continue operations in the subfreezing temperatures of winter, coupled with the ability to reuse produced water, provides additional benefits to field operations. The use of a single component STP as the friction reduction provider also reduces inventory stock and simplifies on-location quality assurance of material usage. Analytical production simulation confirms improvement in productivity index (PI) and estimated ultimate recovery (EUR) forecast.