bluuebunny/crossref_metadata_2025 huggingface dataset:
Drill-in Fluids Design and Selection for a Low-Permeability, Sub-Hydrostatic Carbonate Reservoir Development
Authors: Osode P. I. , Hussain H. A. , Bataweel M. A. , Babbington J. F.
Published: November 2016

Drilling mud-induced damage prevention is essential in low-permeability, low-pressure reservoirs since there is limited pressure drawdown capacity for the damage removal during initial post-drilling well clean-up/flowback operation of producer wells. Avoiding such damage in water injector wells drilled with oil-based mud (OBM) is even more critical because of the risk of injecting residual oil-wet drilled solids and filter cake in the wellbore. The unique characteristics of a central Arabia carbonate reservoir - sub-hydrostatic pressure gradient of ~0.35 psi/ft, average permeability ~2 mD and high-salinity, divalent native brine with SG of ~ 1.15 in combination with a complex well design involving extended multi-laterals and critical petrophysical data requirements, considerably complicated the wells' drill-in fluid (DIF) formulations.

First, generic fluid systems were identified based on analogous reservoir experience and potential formation damage mechanisms likely to be encountered during the drilling and completion phases, i.e., solids and filtrate invasion due to excessive overbalance pressure, external fluid-formation fluid incompatibility and possible aqueous phase trapping. Particle size distribution (PSD) software was then used to design drilling fluid solids composition for a perfect match with the reservoir pore distribution while a conventional bottle test was used to assess the fluid-fluid incompatibilities. Thereafter, laboratory coreflood experiments were conducted to determine rock-fluid interaction effects at an estimated bottom-hole temperature (BHT) of 150 °F and pressure of 1,000 psi. Exposed cores were subsequently subjected to environmental scanning electron microscopy (ESEM) analysis in order to determine filtrate invasion's macro and pore level effects on the core properties.

The investigation resulted in the selection of two customized low-density DIFs: a conventional OBM for the producers and a saline WBM/Hollow Glass Spheres formulation for the injectors. Particle size distribution (PSD) simulation analysis for optimum bridging of the reservoir suggested a blend of fine and very fine grade calcium carbonate in different proportions. As expected, the mudloop tests that were conducted indicated a higher average return permeability of ~77% for the OBM fluid compared to that for the WBM DIF. The fluid-fluid compatibility analysis indicated a risk of inorganic scale precipitation for the mixture of formation brine and surface aquifer water. Finally, ESEM tests on the cores exposed to non-saline WBM DIF filtrate indicated minimal clay swelling and dispersion.

This paper discusses a detailed account of DIF design considerations, PSD analysis, fluid compatibility issues and the laboratory experiments carried out to evaluate and select optimum-performance DIFs for a low-permeability, high-salinity content carbonate reservoir development.
Assessment & Strengthening of Well Control Barriers to Prevent Well Blowout
Authors: Tayab Muhammad R , Abu Aishah Abdel Nasser , Valappil Suhail , Abou Draz Alauddin Mohamed
Published: November 2016

The Oil and Gas (O&G) industry is, by its nature, a high risk industry and poses risks to both staff and workers if appropriate controls are not in place. Failures in implementation of well control safe operating systems have resulted in incidents of varying nature, fires, loss of containment and damage to the environment. A root cause analysis of 6 well control incidents occurred between 2010 and 2014 was conducted and gaps in implementation of expectations of HSE management system identified. A process of embedding learning from incident was developed and linked with 2015 action plan. To prevent well control events, identification of barriers (mechanical, procedural and human) were identified and a process was instituted to strengthen these barriers.
Optimized Drilling Performance by Innovative Application of High-Build-Rate RSS to Sidetrack from Vertical Pilot Hole in Challenging 3D Wells in Unstable Formations
Authors: Amanov B. , Bethancourt R. E. , Sumaidaa A. S. , Al Shaghnaubi M. A. , Abu Aishah A. M. , El Kharbotly M. K. , Mokhti M. Abd , Dua R.
Published: November 2016

An onshore oil E&P operator in the Middle East region had been looking to optimize performance while delivering complex 3D profile wells. The target was to find a solution for performing an openhole sidetrack from a plugged back 8 ½" vertical pilot hole and drill the deviated hole to land horizontally at the top of the reservoir, while following a complex 3D profile trajectory that demanded a minimum continuous dogleg severity (DLS) of 6.75°/100ft across unstable shale formations where conventional RSSs can achieve only up to 4.4°/100 ft DLS.

In previous wells, sidetrack from plugged back pilot hole and drilling of 8 ½" landing section was performed in two runs, first one with a motor assembly and the second one with RSS. However, having two runs resulted in longer operational time and lower average ROP. Previous attempts to drill with a conventional RSS across unstable shale had failed to achieve the required DLS and this practice had been eliminated by the operator. Based on the above, high-build-rate RSS (HRSS) was proposed to overcome theaforementioned challenges to drill the section in one run.

This paper mainly discusses the advantages of accurately kicking off and performing an openhole sidetrack, from a cement plug at the top of an unstable shale formation, and drilling ahead while achieving required high build rates in a single run with new HRSS. This new tool enables deeper kickoff, shorter landing point departures, improved ROP, and smooth borehole in soft or hard formations in complex 3D well profiles, meeting all of the desired objectives and saving rig days, operator costs and resources. Eleven cement plug sidetracks from vertical and shoe-to-shoe drilling runs to section TD were done from Q1 2012 to date using the HRSS with 100% success.

The applications of the HRSS described in this paper are innovative applications designed through thorough planning and risk mitigation. As a result, significant achievements in cost optimization and drilling efficiency enhancement have been realized.
Automated MPD Control System Helps Navigate Through Drilling Problems, Meets Objectives in Shakal Block, North Iraq
Authors: Santamaría Luis A. , Ozegovic Alek , Mehmood Asad , Silva Alfredo , Kropochev Yury
Published: November 2016

This following case study details the methodology followed and challenges encountered while drilling in the Shakal Block of North Iraq. A narrow drilling window and geologically-associated problems in the first well, Shakal-1, were enough to demonstrate that non-conventional drilling techniques are needed to develop Shakal field potential. In case of Shakal-2 and Shakal-3 exploration wells, the 12-¼" and 8-½" hole sections applied Managed Pressure Drilling (MPD) technique and Microflux® control system technology to reach planned objectives and reduced a combined 15 days of drilling time, equating to associated cost savings of US$1.8MM.

The primary objective of drilling with these techniques in the Shakal field was to maintain the Equivalent Circulating Density (ECD) within the operative window and keep the downhole circulating pressure close to formation pore pressure in order to minimize nonproductive time, optimize drilling performance and minimize formation impairment.

In addition to the drilling objectives, MPD help was needed in order to safely facilitate trips to surface derived from normal scheduled operations as well as unprogrammed operations caused by tool failures or drilling problems; in some fields like Shakal, pulling out of hole can be equal or more difficult than the actual drilling operation.

All planned operating windows have some degree of uncertainty. In the cases of Shakal-2 and Shakal-3, Microflux control system technology detected early signs of influx and fluid loss when there was a deviation from the anticipated drilling window.

The flexibility of MPD technique during trips with Stripping Method showed high benefits on these holes sections along with accurate monitoring of well parameters for early detection of influx and losses.

The use of MPD contributed to significant time, cost savings and safety increment for the Shakal-2 and Shakal-3 in the 12-¼" & 8-½" hole sections.
Using Innovative Surface Mounted Technology to Boost Production from Low Pressure Oil Wells and Revive Dead Wells Without any Well Intervention
Authors: Peeran Syed M , Beg Najam , Anazi Rayid , Ajmi Shaleh
Published: November 2016

Innovative Velocity SpoolTM (Surface Jet Pump) technology combined with novel compact separation was tested at a remote onshore wellhead location in Saudi Arabia to see if it could increase multi-phase production from low pressure oil wells that were already producing and revive wells that were backed out/not flowing.

The Velocity Spool (VS) is a passive device which utilises often wasted fluid energy (via a choke) from a high pressure (HP) well to reduce the back-pressure of a low pressure (LP) well and boost its' flow to the production manifold. For the VS to work efficiently on multi-phase oil wells, a compact in-line separator is installed upstream to bulk separate the gas and liquid fluids.

For this trial, one of Caltec's patented VS multiphase skids was installed at an onshore wellhead location and connected to existing HP and LP wells. Production from both wells was diverted to the VS to test its effectiveness. The trial tests lasted 3 months.

Results from the first set of tests showed that the VS boosted production from an LP oil well that was already flowing by an additional average of 400 bbls/d with a corresponding wellhead pressure reduction of 45 psi. Results from the second set of tests showed that the VS revived a dead well that had not been flowing since 2004 and made it flow at an average rate of 1100 bbl/d with a backpressure pressure reduction ranging from 54 to 27 psi. Prior to the trial, several attempts had been made to bring this dead well back into production using other methods but these had not been successful. The results showed conclusively that the VS was very effective in boosting production from LP oil wells using passive surface mounted equipment and avoiding any well intervention. The production gain was achieved by lowering the FHWP of the well and the amount of gain was dependent on the productivity index of the well.

The advantages that the VS offers over conventional technologies such as Multi-phase pumps and ESPs are several: it is tolerant to variations in flow conditions, gas volume fractions (GVF) and associated slugging (without affecting performance), it is surface mounted (so well intervention is not required), low cost, easy to deploy, has no moving parts, consumes zero fuel gas/electrical power and uses already available surplus energy.

This paper reports the trial results and discusses the use of Velocity Spools as an alternative to other boosting methods for oil production. The design and operational criteria of the VS are also highlighted.
The Effects and Modelling of Stress in Hydraulically Fractured Tight Reservoirs
Authors: Bhinde T. , Todman S.
Published: November 2016

Rock stress changes strongly impact well drilling schedules, well placement, fracture design and fluid production in unconventional reservoirs. The objectives of this work are to understand and quantify the effects of stress changes caused by production and fracture stimulation in tight reservoir (shale oil/gas) plays. The implications of stress changes on well drilling (timing), interference between wells due to stresses (well placement) and fracture design (number, placement and timing) are investigated in this work.

Numerical simulation models that integrate several physical effects have been used to achieve these objectives. This integration includes the modelling of fluid flow for reservoir pressure and temperature calculations, full field geomechanical stress, fracture initiation and propagation, rock failure, along with detailed wellbore models.

The work shows that the creation of a single fracture on a well strongly affects the formation of a nearby fracture on the same well. The entire process of multistage hydraulic fracturing can be simulated by integrating the above-mentioned physics in a single model. The results can be used for fracture placement and surface pump duty estimates. The fracture creation model can also be used to estimate the extent of stimulated rock volumes in the reservoir. Stress interference effects between wells can also be investigated using full field modelling.

Furthermore, the closure of natural fractures within stimulated volumes in the reservoir, which reduces permeability affecting future production, can be estimated using full field geomechanics modelling.

The far field effects of stress in unconventional plays show that, although the wells are in pressure isolation, there are strong stress interference effects between wells. The models can be used to generate guidelines on well drilling schedules, well placement, and fracture design and location in such systems.

Several papers exist in the literature on different physical effects studied in isolation within the context of geomechanics in unconventional reservoirs. Importantly, this work integrates the different physical effects in a single model. The work introduces novel considerations on the importance of drilling schedules, well placement and fracture design in unconventional plays.
Go Green - Save Our Earth: GT Low Emissions Combustion Conversion
Authors: Mahmood Tariq , Al Kazeeri Ahmed Hamad , El-Abyouki Mohammed
Published: November 2016

Targeting "Go Green - Safe Our Earth", a state of the art Low Emissions Combustion conversion project was embarked on Habshan Power Generation Berth 80G-105 Frame-6B Gas Turbine.

In line with GASCO emissions reduction strategy, LEC/DLN conversion study of a Habshan power generation berth 80G-105 Frame-6B Gas Turbine was launched as a Pilot. Accordingly, a detailed scope of work was prepared to initiate the retrofit on a turnkey basis. The thorough design review, HAZOP and SIL studies have produced a robust system which includes: LEC Combustion Components, New Fuel Gas Heater and Filter Skids, New Inlet Bleed Heat System, New Fuel Gas Splitter Valve Skid, Flame Detectors and Igniters Replacement and Modifications of the Control System.

With successful implementation of LEC conversion, first retrofit within ADNOC OPCOs, NOx has been reduced from 161 ppmvd to 9 ppmvd (94% Reduction, 575 Tons/Year) whereas CO from 127 ppmvd to 05 ppmvd (96% reduction, 283 Tons/Year). Above reduced emission levels are well below the boundary set by Abu Dhabi Environment Agency for NOx & CO upto 35 & 400 ppmvd respectively. In addition to the remarkable reduction in NOx/CO emissions, the new installed LEC combustion components are of extended life, therefore eliminating the existing combustion inspection every 12,000 Hours saving 10 days shutdowns every one life cycle (48,000-60,000 Hours).

The LEC conversion project presents a unique example of encompassing an innovative approach to achieve tangible environment protection through using improved technology. Further to the implementation of the project, the rewards thus achieved with clean environment are perpetual.
Reservoir Fluid Identification – A Case Study of a Near Critical Fluid From Low Permeability Exploratory Reservoir
Authors: Amjad Kashif , Ahsan Syed Asif , Sultan Mir Asif , Hegazy Gehad Mahmoud
Published: November 2016

Fluid identification is an important step in reservoir characterization and hydrocarbon volume estimation of an exploratory target. Volatile oil / Gas condensate reservoirs are well known for complex behavior due to near critical fluid nature. Objective of this study was to identify fluid nature in a low permeability reservoir where a single phase PVT fluid could not be obtained. This study describes a carefully designed analytical and interpretive workflow that utilized analyses of the separator samples and integration of the data from G&G sources to discern fluid nature.

This paper describes the methodology of identifying fluid nature of collected separator samples from ADCO's exploratory reservoir in a field that has potential to add significant reserves to its portfolio. Due to high pressure encountered during drilling of the exploration target reservoir, Wireline Formation Tester (WFT) pressure gradient and bottom-hole samples were not acquired. Wireline logs were acquired after several weeks and consequently did not help in distinguishing the hydrocarbon type. Production test conducted across the 6 ft thick top layer resulted in 49° API oil with GOR varying from 3000 – 4000 scf/bbl. Three (03) sets of oil and gas separator samples were acquired and physical recombination was performed in the PVT laboratory at reservoir conditions using two different GOR values. Composition analysis of separator liquid was also performed and compared to the same reservoir in analogue fields at comparable depth.

Physical recombination at GOR values of 3000 and 3759 scf/stb exhibited oil and gas-condensate behavior at respective GORs. Composition analysis of separator liquid also indicated significant amount of heavy components (C7+: 65.5% and C12+: 23.6%). Reservoir compositional data was plotted and compared to similar oil / gas-condensate reservoirs from nearby fields. Fluid was identified to be of volatile nature based on PVT study as bubble and dew points pressures were very close in recombined samples. The mud log data showed high total gas reading of 17% in the zone of interest. An assessment of hydrocarbon phase at this high total gas reading based on Wetness (Wh) and Balance (Bh) ratios already indicates presence of light oil. Further PVT work including an attempt to acquire WFT sampling of a single phase fluid is recommended in appraisal wells to thoroughly understand the near critical hydrocarbon phase in the reservoir of interest.
Well Integrity Assessment Using Video Camera Technology - Case Histories
Authors: Al-Zain Ahmed , Al-Mulhim Abdallah , Al-Subaie Fehead , Al-Jandal Ahmed , Al-Mulhem Abdul-Aziz , Al-Hindas Omar
Published: November 2016

Video technology has been used worldwide in various applications, including situations that require diagnosis and evaluation. Advances in video equipment have led to the development of downhole video cameras that are capable of working in the harsh environments encountered in the upstream oil and gas industries.

With the advent of video technology in the oil and gas industries, unique opportunities have been captured to enable efficient and effective means of what is really happening downhole in wells. Video cameras are deployed downhole via either wireline, coiled tubing or drill pipe to inspect well bores. Cameras can be run with down view, side view or both. Common applications include imaging and inspection of wellhead hardware, tubular hardware, fluid movement, leakage, scale deposits, fills, dropped objects, fishing, milling etc. With latest advancements in the deployment methodology, video technology as a downhole diagnostic tool provides the industry with invaluable and useful services.

The video camera assembly connected to a tool string consists of two color video cameras for down and side views. The down-view camera is supported with a light head, which uses LED technology combined with an optimized lens to give color pictures.

The side-view camera has also its own LED lights and a lens with a focal length from 1″ to 8″, providing reasonable views in 2 3/8″ tubing to 21″ tubulars. Rotation of the side-view camera is facilitated by the E-line motor, which is controlled from the surface with side indicator to show where the camera is positioned.

Deviation, high side indicator and internal temperature are digitally transmitted to a surface laptop, providing essential information when viewing images. Additional information such as date, time, running speed, depth, light intensity, and other data could be added to the videos or pictures.

This paper will review applications of video camera in a giant field in Saudi Arabia. Case histories recorded by the video camera will be presented and analyzed to illustrate the usage and benefits of the system in relation to well integrity. It will also highlight findings and remedial actions to restore well integrity.
Silicone Rubber Drill Riser: Handle Drastic Conditions at Reduced Costs
Authors: Kumar Shashank , Jain Udai , Vaish Pranav
Published: November 2016

Risers are considered to be the most critical product in offshore pipeline development taking into account the dynamic loads and sour service conditions they need to withstand. The idea aims at providing a design where the riser is equipped with shock absorbent and thermally insulating material rather than increasing the steel layers around it (conventional method) for making it withstand notorious conditions combined with increased lifetime.

Modification in the existing riser design includes reduction in the steel thickness of the riser, addition of an external high carbon steel casing (of larger diameter) around the outermost layer of the riser and accommodation of a filler material between the reduced outermost steel layer and the added outer steel casing. The filler material used is silicone rubber blended with microballoons (hollow glass microspheres usually of diameter 100 nm – 5 mm), which is non-reactive, corrosion resistant, stable to extreme environments, resistant to high pressure, high temperature and shear force. This will bring to you a riser that can withstand very high pressure and temperature.

A brief comparison between silicone rubber riser and conventional steel riser is presented in the paper. The economics of the method, and the method itself, is compared to the current riser design. The proposed riser design's cost effectiveness lies in the fact that the layers of the riser being protected by highly resistant silicone-rubber are saved from outer corrosion and other damaging factors, therefore increasing their life and providing reusability. Also, the microballoons used to blend the silicone rubber are produced as waste product in coal fired power stations, hence prove to be economical.

The novelty lies in the fact that the proposed riser design provides enhanced properties when compared to the conventional drill riser and also won't add up being a burden on any companies' economics provided its cost effectiveness.
Keeping Oil & Gas EPC Major Projects Under Control: Strategic & Innovative Project Management Practices
Authors: Al-Hajji Hamad , Khan Shehzad
Published: November 2016

The Petroleum industry requires construction and maintenance of ‘upstream’ and ‘downstream’ facilities. Kuwait Oil Company is dealing with exploration and production of crude oil & natural gas. EPC projects plays an important role in generation of new physical facilities to maintain or enhance production. Project management has developed tremendously over time due to evolvement of numerous strategies to deal with construction activities. Schedule and Budget are the two major concerns required to be optimized during execution. Therefore, a very effective & efficient project management system is needed and has to be framed to deal with the major capital construction projects. In effect, help organization make impact on country's economy.

The objective of this paper is to explore few successful in-house projects to find out what went well to identify and analyze key techniques employed to mitigate causes of delay in order to recommend strategic and innovative methods to realize maximum benefits by completing the project on time and within budget. This paper examines various project control methods covering project constraints for formulating strategies, planning, budgeting, procedures, processes, performance measurement, etc. contributing to the successes of acclaimed projects.

The paper has provided advisory-notes on the real-time innovative methods for executing projects, which helps in making the projects more process oriented. The other critical factors, are the best practices to simplify project management techniques and making them more explicit. By applying these innovative approaches, most of the tacit knowledge that is used get converted into an explicit knowledge through proactive participation.

The study has provided an insight in some novel innovative and strategic project management techniques leading to saving in time and cost by overcoming causes of delay and highlighting suitable measures to overcome bottlenecks during project life cycle. Some proven state-of-the-art approaches have been developed in-house by KOC to assure project performance and uphold the Company's reputation and corporate image. Deploying a combination of these methods as a minimum in project execution has shown very fruitful results, which in turn has helped KOC in achieving its strategic objectives.
Subduing Harmful Exposure of BTEX by Improving Facility and Practices
Authors: Veerakumar Ukkirapandian , Al Shaali Saud Jamal , Abbas Ahmad
Published: November 2016

Objective

The objective of this project is to survey the current exposure level of BTEX to laboratory technicians by measuring intake and their metabolites in urine sample. It is also to take appropriate actions to control their exposure through improvement in facility, practices and corrective actions.

Methods, Procedures and process

Occupational health survey on technicians performing sampling and analysis of crude oil, condensate, paraffinic naphtha etc. was carried out every year by a competent external agency. The BTEX vapors were absorbed in a passive sampler for 8 hours held close in the breathing zone of technicians. The absorbed components were extracted and analyzed using chromatograph for benzene, toluene, ethylbenzene and xylene. Their metabolites were determined by collecting pre/post urine samples after extended hours of exposure.

Results, observations and conclusions

In 2010 BTEX were below the threshold and detection limits in 4 cases out of 5. The BTEX metabolites were below detection limit (DL) and Threshold Limit value (TLV). In Oct 2012, the survey indicated abnormal and higher BTEX values; particularly Toluene was 120 mg/m3 as against the TLV of 75 mg/m3. Several steps were taken which included training, awareness of technicians, good laboratory practices, personal protective equipment and improved exhaust system and ventilation. The air intake velocity of fume hoods, HVAC system, the ambient temperature etc. were inspected and monitored. Additional fume hood was installed to extract vapors. The activated carbon filters of all 19 air extraction blowers were replaced in Sep-2013 to ensure increase in fume hood air velocity and for complete absorption of BTEX in these filters so that there is no air pollution.

A special type of face mask (Model 3M 9922) was introduced which prevents direct inhalation of volatiles. BTEX exposure was minimized by improving the performance of fume hoods, extraction system, exhaust bowers and HVAC Units. Training of technicians and their awareness on release of BTEX and ways of minimizing their exposure helped us to implement a good laboratory practice thereby minimizing exposure. Strict adherence to safety procedures and using appropriate personal protective equipment reduces inhalation of BTEX. Improvement in the exhaust filters minimized air pollution. The subsequent surveys indicated that the working place is well protected against release of BTEX and there is no risk to health of the staff. By the whole process we could meet both local and international legislation on BTEX emissions.

Novel / additive information

This significant improvement can be shared with ADNOC group of companies having similar work place hazards. This can be considered as an achievement and operational excellence towards ADGAS commitment in safeguarding the safety of our employees and looking for improving the work environment.
Implementation of an Early Drilling Problem Detection System with Dynamic Look-Ahead Simulations to Assist Drilling Decisions on a Shallow ERD Well in the Barents Sea
Authors: Kucs Richard , Trauner Stephan , Abrahamsen Egill , Hollinger Gerald
Published: November 2016

In the petroleum industry, software systems designed to monitor real-time drilling parameters are constantly evolving, with the aim of providing improved capabilities in the early detection of dysfunctions during the construction of wells. When optimally applied and embedded within a drilling team, such software systems have been proven to be of great benefit to the operation by helping to avoid major drilling problems. The trust in and the implementation of the information provided by such software are crucial factors of success, and herein lay the biggest challenge.

This paper investigates the application of a cutting-edge, early drilling problem detection system for the drilling of a complex, shallow horizontal exploration well. It determines if the use of the system was successful and looks at improvements that can be made to the system for future operations. The study was performed by a combination of reviews of the software output, interviews with key personnel involved, experience's from other cases, and theoretical knowledge.

The case well was drilled offshore Norway in the Barents Sea, with a rig contracted solely for this well. The operator employed a permanent drilling team in the local office in Stavanger, with key personnel located on the rig. The company providing the early drilling problem detection system had an engineer at the rig site as part of the drilling team. The system installation was coordinated by the local office while being supported in setup and organizational matters by the well engineering global support team at the operator's head office in Vienna. The implemented system simulated the physics in the well bore to provide early identification of drilling problems, and produced dynamic look-ahead simulations to assist drilling decisions. Key factors such as communication patterns, when and which functionalities of the system were used, how the results were fed back into the operational decision making, the organizational set up, and the physical placement of the various personnel and the technology used will be investigated. Additionally, the paper will look at the learnings and potentials for future implementations of such a system.
New Saturation Functions for Carbonate Reservoirs TZs based on Fundamental Petrophysical Properties
Authors: Raheem Oriyomi N. , Belhaj Hadi
Published: November 2016

In the present study a core analysis program including NMR measurements were performed to get a better petrophysical characterization of carbonate reservoir transition zone in the Abu Dhabi region. The results reveal three distinct rock types with average NMR-T2 cutoffs of 292 ms, 164 ms and 63 ms for the topmost, middle and lowermost samples of the reservoir respectively. Electrical resistivity and capillary pressure-water saturation were also measured at ambient and reservoir (2500 psi and 85 °C) conditions using a DCI Pc-RI system mimicking drainage and imbibition to investigate the hysteresis and variation in saturation exponent.

It was found that the cementation exponent increases from 1.9 to 2.3 under overburden conditions and decreases in a stepwise manner during reduction of overburden, but not to the initial value due to hysteresis. This implies that the electrical parameters at ambient condition would lead to underestimation of water saturation. The saturation exponents estimated during drainage and spontaneous imbibition at reservoir conditions range from 1.6 – 7.5 for the different rock types tested in this study. New saturation functions were developed for each rock type from the measured electrical parameters at reservoir conditions by using the modified Archie’s and Skelt Harrison’s equation for the transition zone of this carbonate reservoir. The outcomes of the present study lead to a correction of the field resistivity log data that, overestimate the water saturation and hence predictions of saturation distributions, mobility and original oil in place.
Locating and Imaging Leaks Using New Acoustic Array Technology
Authors: Walters Darren , Hill Freeman , Lu Yinghui , Nguyen Nam , Jagannathan Srinivasan , Ang Yi Yang , Reid Joseph
Published: November 2016

With the growing number of mature wells globally, more integrity issues are arising, thus creating a need for diagnostic technologies. Aging wells can develop corrosion or mechanical failures, allowing unwanted communication. Existing technologies allow the identification of leak depths, but do not provide reliable information regarding radial location. A new acoustic array technology helps identify wellbore leaks by depth and radially. A description of the leak's flow pattern in and around the wellbore can also be obtained. Having a clearer picture of the location and leak type makes operational planning more efficient and helps prevent nonproductive time (NPT).

Typically, noise tools have used a single hydrophone or a few sensors to capture noise measurements. An array of sensors can capture an acoustic event from multiple points simultaneously and uses this information to localize the leak. This measurement removes the high dependency on the frequency and magnitude alone to identify the location of a leak. During well testing, sound waves travel up and down the pipe and build standing waves in the pipe, giving a false echo of the leak location when just examining frequency and magnitude. The array negates these inaccuracies and accurately identifies the leak's vertical and radial location, even when frequency and magnitude alone show a different response.

Operators have field tested a new acoustic array tool in aging wells. During this time, the tools were exposed to various leak conditions and problems. The array tools have shown value by identifying depth of communication and the radial location in the wellbore. The radial locater helped discern whether it was tubing, Annuli A, Aannuli B, or an outer casing issue. A unique flow map imaging technology provides a detailed picture of sound-related flow in and around the wellbore.

The new acoustic array technology provides the ability to generate two-dimensional (2D) images of flow-generated noise, which can then be used to extract both leak-depth and radial location. This 2D image is structured to show the makeup of the wellbore and, through a spectrum of color, displays the high flow area where the leak is passing through the tubular section and traveling. The image also identifies where no flow is observed for easy identification of flowing annuli.
Polymer Injection to Rejuvenate a Supermature Oil Field, Polymer Pilot Results, 8 TH Reservoir, Austria
Authors: Clemens Torsten , Kornberger Martin , Lueftenegger Markus
Published: November 2016

The 8 TH reservoir is a "supermature" field which has been in production for more than 65 years. It was waterflooded for more than 50 years resulting in a current water cut of 96 %. The field contains medium viscous oil (in-situ viscosity 19 cP) and hence was considered for polymer injection despite the high water cut which was suggested by some authors to be challenging for polymer injection.

An inverted five spot unconfined polymer injection pilot was performed to reduce the subsurface uncertainties, determine if polymer flooding could lead to incremental oil in "supermature" fields, improve the operating and monitoring capabilities and improve the economic model for full-field implementation.

The results of the pilot show that an increase in 5- 10 % of the recovery factor can be achieved in the pilot area. The reasons for incremental oil production by polymer injection in this "supermature" field are acceleration along high permeable flow paths but more importantly substantial flow diversion in this heterogeneous reservoir. In the pilot area, the highest oil production since 1978 was achieved.

The main uncertainties related to surface handling of the polymer solution prior to injection, injectivity and incremental oil recovery could be reduced by monitoring of various parameters. In particular tracers and molecular weight distribution of polymers were measured to improve the understanding of the polymer solution effects on reservoir performance.

In addition, numerical simulations concerning injectivity and reservoir performance were performed to further improve the understanding of the processes and be able to optimize the operations. The simulations included polymer solution injection induced fractures as well as geological, reservoir fluid/relative permeability and polymer solution property uncertainties and allowed forecasting under uncertainty.

The cost structure of the polymer pilot was used to evaluate full-field economics taking learning curves, upscaling and costs optimisations into account.
EOR by CO2 Emulsions Better Sweep Efficiency and Improved Recovery
Authors: AlOtaibi Fawaz , Zhou Xianmin , Habah Abdulla , Kokal Sunil
Published: November 2016

Carbon dioxide (CO2) flooding projects have shown a large potential for recovering additional oil beyond waterflooding, but in many cases this process is handicapped, especially in thick reservoirs, by CO2 gravity override. Different methods have been used to overcome the CO2 gravity override by either increasing CO2 density, viscosity, or reducing its relative permeability. Reducing the relative permeability of CO2 by the water alternate with gas process has received much experimental and theoretical attention. Although this method helps to control fingering, it also introduces gravity segregation issues. An alternative approach to reduce the mobility is to disperse CO2 as a foam or as an emulsion in a continuous aqueous liquid phase. This paper provides some data and results for a new emulsion system that behaves as a conformance control agent, and also to enhance the recovery of oil following water and CO2 floods.

The CO2 emulsion system used in this study consists of 70 vol% supercritical CO2 (sc-CO2), 30 vol% of water-based polysaccharide linear polymer and a foaming agent (surfactant). This new emulsion system has the ability to be created in situ to provide better mobility control of the injected CO2. Special parallel dual coreflooding experiments were conducted using live oil at reservoir conditions to investigate the effectiveness of the CO2 emulsion system in conformance control and enhancing oil recovery. Several experiments were conducted to explore the effect of the injection rate, injection mode and slug volume on incremental oil recovery using dual core carbonate composite stacks with permeability contrasts up to 60 based on brine permeability.

Results based on this study show the CO2 emulsion's ability to significantly reduce permeability of the higher permeable cores resulting in enhancement of incremental oil recovery from the lower permeable cores. The majority of oil was recovered from the high permeability core during the initial water and CO2 flooding when both cores were placed in parallel. The oil recovery from the low permeable cores by waterflooding was similar to that of the high permeability core, but significantly less during the first CO2 flood. After a slug of CO2 emulsion was injected that blocked the high permeability core, it resulted in 21% incremental oil recovery from the low permeability core during a second CO2 injection. The results demonstrate the improvement in both areal and vertical sweep efficiencies by CO2 emulsions by stabilizing viscous fingering and gravity override issues. The results bode well for scale up for a field trial.
Developed Material Balance Approach for Estimating Gas Initially in Place and Ultimate Recovery for Tight Gas Reservoirs
Authors: Al-Fatlawi Omar , Mofazzal Md Hossain , Hicks Steven , Saeedi Ali
Published: November 2016

The gas material balance equation (MBE) has been widely used as a practical as well as a simple tool to estimate gas initially in place (GIIP), and the ultimate recovery (UR) factor of a gas reservoir. The classical form of the gas material balance equation is developed by considering the reservoir as a simple tank model, in which the relationship between the pressure/gas compressibility factor (p/z) and cumulative gas production (Gp) is generally appeared to be linear. This linear plot is usually extrapolated to estimate GIIP at zero pressure, and UR factor for a given abandonment pressure. While this assumption is reasonable to some extent for conventional reservoirs, this may incur significant error when applied for unconventional tight gas reservoirs. The implementation of multi-tank, compartmented reservoir models are reported to better represent the behaviour of tight gas reservoirs. This study focus to develop a simple numerical method to solve the MBE using the concept of multi-tank, compartmented reservoir model. A simple and practical computational tool is developed by solving the numerical model using False Position iterative method. The tool is applied to calculate GIIP and UR factor for an Australian tight gas field after validation of tool based on history matching. The results demonstrated that the developed tool can be used for the better estimation of GIIP and UR factor with better accuracy. The program can also be used as an efficient tool, especially in the case of homogenous tight gas reservoir, as an alternative to the reservoir simulation to understand the pressure decline behaviour with cumulative gas production; and to estimate GIIP and UR factor.
Multi-Tasking Valve MTV Technology Optimizing Operations for Challenging ICD's Liner Installation in ADMA-OPCO, Abu Dhabi, UAE
Authors: Darceuil Nigel , Mohamed Mohamed El-Sayed , Sabri Abdul Moez , Vicario Roberto , Agilzhanov Nariman , Gharbawi Shihabeldin Mustafa , Musa El-Rasheed , AL-Shamsi Mohamed Khamis , Cortes Wilmer Ferney , Abdelfattah Tarik A. , Pande Nandita , Bamidele Tajudeen
Published: November 2016

Inflow Control Device's (ICD's) are gaining popularity in providing solutions to permeability variance in heterogeneous reservoirs together with water breakthrough occurrences. However, the installation of these devices requires the success of a series of critical operational steps. The MTV feature of the ICD liner allows combination and simplification of these steps ultimately optimizing the installing operation in a challenging ICD liner in ADMA-OPCO.

The installation process essentially requires the top of liner packer to be set followed by zonal isolation packers while allowing the 18 ICD's to be opened after installation. A closed loop for pressure application is needed to set the liner packers consequently requiring a second run for the open pathway in the ICD's. MTV technology allows the ICD to be run in the open position while allowing a closed loop for pressure application therefore saving an extra run, reducing risks and increasing overall operational efficiency.

A single run executed ensured packers were set to secure the liner in place and that there was no requisite for a separate run thus eliminating the risk for the shifting tool to accidentally open/close the ICD's pathway due to a challenging closely spaced liner configuration. Production Logging Tool (PLT) assessment confirmed the objective of equalizing the reservoirs and providing isolation via packers thus allowing a high permeability zone to accept less volume of water was achieved having closely comparable design injectivity targets. Besides zero Non-Productive Time (NPT) for this operation, a recognizable savings was realized both in cost and risk reduction. Extensive multi-disciplinary meetings, several site visits, workshop, risk assessment, excellent communication and on site supervision are the main contributors to the success of this operation. This success encourage the onset of several other wells being pursued using this MTV technology for ICD's in ADMA-OPCO's field.

This MTV technology application has proven its worth as a continuous improvement tool to alleviate previous situations in ADMA-OPCO, thus demonstrating to rise as a pioneer for ICD design. We continue to investigate for our future wells a circulation sub to add additional capability in our ICD liner installation operations.
Inspection of Non-Piggable Piping Using InVista Technology
Authors: Al Jasmi Ashwaq , El Sinnary Omar
Published: November 2016

As a part of GASCO strategy to launch joint initiatives in field testing of latest available NDT technologies with the lowest cost required, and in order to explore the most reliable alternatives in the industry for higher inspection accuracy of non-piggable piping & pipeline with the aim of validating these for future adoption across company's operating sites, GASCO has successfully completed a pilot project using state-of-the-art mini-pigging (InVista technology) for non-piggable pipelines.

The InVista intelligent mini-pigging technology incorporates new high-fidelity ultrasonic probes and provides high accuracy in estimating quantitative wall thickness data vis-à-vis the relatively outdated UT Tethered in-line inspection technology. The InVista technology benefits are summarized as follows; Provides practical solution for non-inspectable pipeline and piping.Achieves higher accuracy in data than the conventional inspection technology.Operates at minimum to no risk and also significantly reduces the downtime of these assets, which is a substantial cost optimizer.Provides a medium to long term perspective for a cost-effective asset integrity management (Cost saving approx.60%).

GASCO performed a pilot project using InVista technology to inspect a non-piggable 8" carbon steel underground fire water line (1.8 Km length) in Buhasa plant, which has never been inspected since 1980.

The InVista inspection results have been confirmed via UT site verification survey for the selected locations where the survey results were matched with the InVista results.