bluuebunny/crossref_metadata_2025 huggingface dataset:
Farnsworth Field CO2-EOR Project: Performance Case History
Authors: Ampomah W. , Balch R. S. , Grigg R. B. , Will R. , Dai Z. , White M. D.
Published: March 2016

The Pennsylvanian–age Morrow sandstone within the Farnsworth field unit of the Anadarko basin presents an opportunity for CO2 enhanced oil recovery (EOR) and sequestration (CCUS). At Farnsworth, Chaparral Energy's EOR project injects anthropogenic CO2 from nearby fertilizer and ethanol plants into the Morrow Formation. Field development initiated in 1955 and CO 2injection started December 2010. The Southwest Regional Partnership on Carbon Sequestration (SWP) is using this project to monitor CO2 injection and movement in the field to determine CO2 storage potential in CO2-EOR projects.

This paper presents a field scale compositional reservoir flow modeling study in the Farnsworth Unit. The performance history of the CO2 flood and production strategies have been investigated for optimizing oil and CO2 storage. A high resolution geocellular model constructed based on the field geophysical, geological and engineering data acquired from the unit. An initial history match of primary and secondary recovery was conducted to set a basis for CO2 flood study. The performance of the current CO 2miscible flood patterns were subsequently calibrated to the history data. Several prediction models were constructed including water alternating gas (WAG), and infill drilling using the current active and newly proposed flood patterns.

A consistent WAG showed a highly probable way of ensuring maximum oil production and storage of CO2 within the Morrow formation.

The production response to the CO2 flooding is very impressive with a high percentage of oil production attributed to CO2 injection. Oil production increasingly exceeded the original project performance anticipated. More importantly, a large volume of injected CO2 has been sequestered within the Morrow Formation.

The reservoir modeling study provides valuable insights for optimizing oil production and CO2 storage within the Farnsworth Unit. The results will serve as a benchmark for future CO2–EOR or CCUS projects in the Anadarko basin or geologically similar basins throughout the world.
Conformance Solution Improved Oil Recovery in a Naturally Fractured Carbonate Well
Authors: Hernandez-Solana Leticia , Tellez-Abaunza Jonnathan , Garcia-Montoya Benjamin
Published: March 2016

One of the primary problems for mature oilfield operators is the production of undesired fluids, such as water or gas. Cantarell is a mature field wherein one of the greatest challenges is managing produced water. Mature oil fields experience severe water production, which can be challenging in naturally fractured carbonate reservoirs that produce through a thick layer of oil. A new technology combining two conformance systems was used to alleviate water production in a well in this field, returning production to optimal levels.

The study well (Well A) was shut in because of high water cut (90 to 100%), and post-analysis of this problem showed water coning from fractures in the Lower Cretaceous formation. The well has a unique interval, and perforating a deeper interval was not possible because the water-oil contact (WOC) was close. The solution selected for this case was a combination of two conformance technologies for water control that permit sealing high permeability channels and fractures and, more importantly, help provide selective water control—one is a swelling polymer designed to shut off water channels, fractures, or highly vugular zones, and the other is hydrocarbon-based slurry cement that reacts on contact with water. The result was the recovery of a producer well with 1,197 BOPD with 14% water cut. After 19 months, production averaged 1,300 BOPD for that month with 40 to 66% water cut.

Correctly diagnosing the problem and combining conformance technologies can help operators resume production of wells considered lost because of undesired fluids production. Therefore, this technology could be used to benefit reservoir optimization and production.
Introducing a Novel Enhanced Oil Recovery Technology
Authors: Parsons C. , Chernetsky A. , Eikmans D. , te Riele P. , Boersma D. , Sersic I. , Broos R.
Published: March 2016

In this paper we present a novel Chemical EOR technique in which dimethyl ether (DME), a widely-used industrial compound is utilised as a miscible solvent in conjunction with conventional waterflooding. The end effect of the solvent's application is an increase in oil recovery significantly greater than that typically achieved by waterflood alone.

The method of application is straightforward, taking advantage of DME's solubility in both water and hydrocarbons: water is used as a carrier for DME during injection and upon contact with reservoir fluids, DME preferentially partitions into the hydrocarbon phase thereby swelling and mobilising the oil phase. This is followed by a DME-free water chase to recover the remaining mobile oil and DME. Residual oil saturation after sweep is reduced, significantly below that typically achieved by waterflood alone. Furthermore, the DME can be extracted from the produced wellstream fluids by distillation and/or absorption processes, and re-used for injection.

The DME Enhanced Waterflooding (DEW) technique takes advantage of the unique solubility properties of dimethyl ether to improve oil mobility and reduce residual oil saturations. Significant research into the pressure-volume-temperature (PVT) behaviour of DME and DME/crude oil mixtures has been carried out in recent years; in particular the partitioning behaviour of the solvent and mixing rules for the various mass transfer properties affecting mobility. The PVT-driven behaviour and the overall displacement efficiency of the DEW technique have been observed in core flood experiments using both carbonate and clastic core plugs.

The DEW technique can be deployed in reservoirs with different geologies, fluid properties and conditions (pressure, temperature and salinity), making its application envelope much larger than that of any of the currently available EOR technologies.
Linking Low Salinity EOR Effects in Sandstone to pH, Mineral Properties and Water Composition
Authors: Piñerez T. Iván D. , Austad Tor , Strand Skule , Puntervold Tina , Wrobel Stanislaw , Hamon Gérald
Published: March 2016

Low salinity water injection in sandstone is an emerging technology just on the verge of being implemented full field in the UK and in Alaska, USA. Laboratory studies are important for providing relevant and well interpreted data before performing the field trial. However, laboratory investigations show varying results on low salinity EOR, most probably because of a limited understanding of the nature of the process. Recently we have published a "Smart Water" EOR mechanism where pH changes at the rock surface is inducing the wettability alteration, improving positive capillary forces and microscopic sweep efficiency. Researchers have experienced rather poor low salinity EOR effects from 17 different sandstone outcrops from the USA.

In this work we have investigated 6 of the same 17 outcrops, and according to our chemical understanding, some factors are more important for observing LS EOR effects in sandstone. It is the increase in pH, ΔpH, obtained when the high salinity (HS) formation water is displaced by the low salinity (LS) injection water, and it is the initial pH and the amount of active cations (Ca2+) in the formation water that are related to the initial wetting.

We have established a link between the poor low salinity EOR effect from all 6 outcrops and the corresponding pH change observed when switching from high salinity to low salinity injection water. The presence of different types of minerals such as clay, feldspars and anhydrite will influence the pH change, and must be taken into account. Additionally, we have seen that the formation water composition has strong influence on the low salinity EOR effect. Using a formation water with salinity like seawater (FW1 ~35 000 ppm) showed only a minor tertiary low salinity EOR effect, 0.74 %OOIP, corresponding to a low pH gradient of 0.5. While experiments using a high salinity formation water (FW2 ~100 000 ppm) showed a 5 % OOIP recovery, corresponding to a larger pH gradient of 2.0.

The results observed are in agreement with the suggested chemical mechanism for the low salinity EOR effect, confirming that it is the pH gradient that triggers the low salinity EOR effect. In addition, the pH screening test used in this work proved once again to be a reliable tool to evaluate the low salinity EOR potential.
Experimental and Numerical Studies of CO2 EOR in Unconventional Liquid Reservoirs with Complex Fracture Networks
Authors: Sun Jianlei , Zou Amy , Schechter David
Published: March 2016

With the synergy of horizontal drilling and hydraulic fracturing techniques, commercial production of Unconventional Liquid Reservoirs (ULR) has been successfully demonstrated. Due to the low recovery factor of these reservoirs, it is inevitable that Enhanced Oil Recovery (EOR) will ensue. Experimental results have shown promising oil recovery potential using CO2. This study investigates oil production mechanisms from the matrix into the fracture by simulating two laboratory experiments as well as several field-scale studies, and evaluates the potential of using CO2 huff-n-puff process to enhance the oil recovery in ULR with nano-Darcy range matrix permeability in complex natural fracture networks.

This study fully explores mechanisms contributing to the oil recovery with numerical modeling of experimental work, and provides a systematic investigation of the effects of various parameters on oil recovery. The core scale modeling utilizes two methods of determining properties that are used to construct 3D heterogeneous models. The findings are then upscaled to the field scale where both simple and complex fractures in a single stage are modeled. The effects of reservoir properties and operational parameters on oil recovery are then investigated. In addition, this study is the first to present simulation results of CO2 huff-n-puff using complex fracture networks which are generated from microseismic-constraint stochastic models.

Diffusion is proven to be the dominant oil recovery mechanism at the laboratory scale. However, the field-scale reservoir simulation indicates diffusion is negligible compared to the well-known mechanisms accompanying multi-contact miscibility. This includes swelling, viscosity reduction, and gas expansion in the matrix. Overall, the CO2 huff-n-puff process was found to be beneficial in both models in terms of enhancing the ultimate oil recovery in ULR.
A Research Model for Using Sacrificial Agents to Enhance Surfactant Performance in Liquids Rich Shale Reservoirs
Authors: He Kai , Xu Liang
Published: March 2016

Post-fracturing production data analysis indicates stimulation of some west Texas wells with surfactant additives did not enhance production as high as expected. Analysis of flowback and produced water for surfactant residues revealed 99% of surfactant was retained inside wells (Rane and Xu 2015). This indicates surfactant plating out on rock in the near-wellbore (NWB) region, restricting travel deeper into the reservoir, which compromises well performance. This study presents a sacrificial agent (SA) to cover rock surface near the wellbore, allowing surfactant to penetrate the formation.

Literature precedent exists that polyelectrolyte (PET)-based SAs could significantly reduce surfactant adsorption not only onto a variety of outcrop minerals (Carlpool dolomite, calcite, kaolinite, Berea sandstone, Indiana limestone, etc.) and metal oxide nanoparticles, but also unconventional shale formulations in which surface area can be up to 700 m2/g. In this study, the adsorptions of surfactant and SA to proppants were first examined. Results indicate no adsorption was observed to proppant for both surfactants and PET-based SAs. SAs (0.5 to 1 gal/1,000 gal (gpt)) were then injected with surfactant (1 to 3 gpt) at an appropriate ratio into column-packed shale formulations (primarily composed of calcite, dolomite, quartz, illite, pyrite, and plagioclase feldspar) to investigate its effectiveness in controlling surfactant retention caused by adsorption. Laboratory testing revealed injection of 3 gpt mixture of surfactant and SA has a similar adsorption profile (surface tension as a function of time) as 3 gpt surfactant alone based on the dynamic surface tension measurement. Notably, the addition of SAs resulted in lower surface tension and enhanced hydrocarbon solubility; and thus, an improved oil recovery by surfactant was achieved as evidenced by the oil recovery tests. Additionally, 68% friction reduction of the fracturing fluid with surfactant and SA was sufficient for the field operation compared to the guar-based fluid used in the hydraulic fracturing applications.

As a result of the laboratory findings, field trials were executed on a three well pad in the Permian basin (PB). For the first 30 days oil and gas production appeared to be significantly higher than the average production from offset wells in the same area that were previously fractured with the same surfactant.
Effect of Heterogeneity on Propagation, Placement, and Conformance Control of Preformed Particle Gel Treatment in Fractures
Authors: Imqam Abdulmhsin , Wang Ze , Bai Baojun , Delshad Mojdeh
Published: March 2016

Preformed particle gels (PPG) have been successfully applied as a plugging agent to solve the conformance problem in fractured reservoirs. They are injected to plug fractures and then divert displacing fluid into poorly swept zones and areas. However, PPG propagation and plugging mechanisms through open fractures have not been studied thoroughly. This paper investigated the influence of some factors (particle size, brine concentration, heterogeneity, injection flow rate, and brine salinity) on gel injectivity and plugging performance for water flow through opening fractures. Five-foot tubes were used to mimic opening fractures. Three models were designed to gain understanding on how fracture geometry and PPG properties affect gel injection and plugging efficiency, including (1) single fracture with uniform fracture width, (2) single fracture with different widths, and (3) two parallel fractures with different width ratios between each other. Results from single uniform fracture experiments showed that PPG injection pressure was more sensitive to gel strength than gel particle size. When large PPG size and high gel strength were used, high injection pressure and large injection pore volume were required for PPG and brine to reach fracture outlets. Results from single heterogeneous fracture model experiments showed PPG injection pressure increased as the fracture heterogeneity in sections increased. Particle gel accumulated at the choke point within each fracture and caused injection pressure to increase accordingly. Furthermore, results showed that having a lower salinity within a fracture, which was less than the brine salinity that was used to prepare PPG, would improve the PPG plugging efficiency for water flow. Parallel fracture models results showed that when weak PPG was used, a large volume of PPG flowed into a large fracture width and a small portion of the gel particle volume flowed into small fracture width. However, with increased gel strength and fracture width ratio, PPG only flowed through larger fracture widths. This paper demonstrates important impact elements of gel propagation and water flow for different opening fracture situations.
Dynamic Attributes for Characterization of Complex Oil Reservoirs, A Case Study from R. Trebs Oil Field, Timan-Pechora Basin, Russia
Authors: Shumatbaev K. , Privalova O. , Gainullina E. , Akhmetzyanov R. , Chervyakova A. , Melnikov A. , Fedorov A. , Kuchurina O.
Published: March 2016

The paper presents the void space configuration and geometry models for the Lower Devonian and Upper Silurian reservoirs of R.Trebs oil field. The productive formations are characterized by heterogeneity and complex architecture of the pore space which includes practically all types of voids – primary and secondary or epigenetic pores, fractures and solution vugs developed along fractures. The study reviews small to large scale methods for analysis of vug component as a fraction of the void volume in the reservoirs – laboratory (thin sections, conventional core plugs and whole or full-diameter core samples), rock physics (sonic waveform logging, nuclear magnetic resonance, imagers) and production logs (flow profile, productivity). The results are used to develop simplified models for reservoir characterization of the pore space architecture for the Lower Devonian and Upper Silurian productive formations and also to identify trends in well productivity as a function or rock physics properties of the reservoirs.
New On-Command Integrated Under Reamer Elevated Drilling Performance, Reduced Operational Risks and Lowered Cost: A Case Study in the Oseberg South Field
Authors: Ahlberg Jill , Fang Lei , Hoff Kjell Rune , Manseth Arvid , Schwartze Sascha , Larsen Johan Fredrik , Borlaug Kjetil , Longvastøl Karl Gerhard
Published: March 2016

This paper presents technical features and associated benefits of a recently developed under reamer technology and its applications in the offshore Norway Oseberg South field to drill 12 ¼″ × 13 ½″ and 8 ½″ × 9 ½″ sections. It discusses the results of the operations and demonstrates how the operations benefited from the new technology.

In today's drilling operations, expandable reamers are broadly used to support optimized casing and completion programs and to reduce operational risks such as high Equivalent Circulating Density (ECD), drilling troublesome formations and reaming well path conformities. The currently available hole enlargement technologies, such as ball drop and hydraulically activated reamers, carry intrinsic risks and limitations.

To address the challenges associated with currently available under reamer technologies, expandable reamer technology was recently developed jointly by a service company and a major operator, and was field tested offshore Norway. The under reamer, which is fully integrated with the company's existing Rotary Steerable System (RSS) Bottom Hole Assembly (BHA), provides unlimited, on-command activation cycles, optimal placement within the BHA in multiple configurations and real-time feedback via mud-pulse telemetry. The feedback from the reamer includes confirmation of blade activation status, health of the tool, and vibration and stick-slip measurements. Because of the flexibility of its placement in the BHA, the reamer can reduce the length of the rat hole to a minimum of 4 m compared to the standard 30 to 70 m in the same drilling run, eliminating the need for a dedicated clean-out run. The reamer also enables reliable and unlimited activation / deactivation cycles with each cycle taking less than 5 minutes, saving operational costs for the operators.

The under reamer was successfully deployed to drill challenging 12 ¼″ × 13 ½″ and 8 ½″ × 9 ½″ sections in the offshore Norway Oseberg South field. The 2497 m long 12 ¼″ × 13 ½″ section and 900 m long 8 ½″ × 9 ½″ section were both drilled to Total Depth (TD) in one run, with all requirements on directional control and Measurement While Drilling (MWD) / Logging While Drilling (LWD) met. The technology was proven to be a reliable and flexible hole enlargement while drilling solution that elevates drilling performance, reduces operational risks and lowers operational costs.
Production of Sedimentary Methane Hydrates by Depressurization
Authors: Almenningen Stian , Flatlandsmo Josef , Fernø Martin A. , Ersland Geir
Published: March 2016

The voluminous amounts of hydrates found in nature are distributed across all continents and pose a huge possibility for future energy harvest. In fact, the total amount of energy stored in hydrates is predicted to be in the same range as conventional fossil fuels combined. Successful exploitation of this energy supply will serve as a vast and relatively clean source of fossil fuel for the remaining of the fossil era. Natural gas hydrates consist of guest molecules encapsulated inside cavities formed by hydrogen-bonded water molecules. The origin of the encaged gas may be biogenic or thermogenic with methane being the most common hydrate former in the earth. Methane hydrates are stabilized at elevated pressures and low temperatures and are mainly located in onshore permafrost regions and in marine sediments offshore.

This paper review how production of methane from hydrates can be triggered by dissociation of the hydrate structure. Techniques leading to dissociation of hydrates are summarized by pressure depletion, thermal stimulation and injection of inhibitors. Depressurization is considered to be the most cost-effective method and is easily implemented in gas reservoirs with overlying hydrate layers. Examples and status of pressure depletion tests on field scale will be reviewed. In hydrate reservoirs not adjacent to gas zones, the success of pressure depletion is dependent on sufficient permeability to allow for pressure perturbations to reach within the hydrate reservoir and to allow for flow of dissociated gas. This effect has been investigated in this paper by performing controlled pressure depletions on hydrate-filled sandstone cores. Dissociation pressures at given temperatures have been quantified as well as recovery of methane as function of pressure-decrements below dissociation pressure. A 2D porous silicon wafer micromodel was used to gain insight on the mechanisms of hydrate dissociation. Direct visualization of hydrate melting induced by both depressurization and heating is reported from pores replicating authentic sandstone pores.
Innovative Concepts in Wireline Continuous Coring
Authors: Ashena Rahman , Vortisch Walter , Prohaska Michael , Thonhauser Gerhard
Published: March 2016

Coring in unconventional reservoirs with typical unconsolidated formations has introduced additional challenges requiring more innovative concepts to be developed. These requirements, economic issues of unconventional reservoirs, and also issues of conventional coring particularly in regard to excessive trip times incurred have recently led to widespread attention to wireline continuous coring (WCC) modified from mining industry to petroleum industry applications. This coring method has contributed to coring deep formations, long core sections, multiple zones, jam prone formations, exploration zones or areas with unknown core points. Currently, WCC is suffering from several drawbacks while some recent attempts have been made to remove them. In this accordance, this work is missioned to remove some existing defects by adding some innovative concepts to be applied to the ordinary WCC. Therefore, a more efficient continuous coring method is aimed which includes enhanced coring key performance indicators.

Therefore, several identified challenges of WCC are considered to be removed or alleviated by innovative concepts to be added. The challenges consist of un-flushed inner tube while run in hole, limited retrievable core size, in-situ/pressure coring hazards (i.e. safety issues, complex sealing, etc.), slick line issues (rig time, torque, rupture, etc.), untimely and inefficient decision making while coring/drilling, non-optimized coring/drilling and tripping induced core damage in WCC.

In order to address these issues, as novelty measures, first an inner tube flushing system is proposed for flushing inner tubes prior to commencing coring. Second, casing drilling coring is recommended in order to obtain larger core sizes contributing to improved core analysis. Third, in-situ downhole measurement and sampling systems are proposed to measure properties of in-situ fluids in order to complete or replace pressure/in-situ coring systems and ensure safety. Fourth, an innovative mode conversion system is proposed to mitigate slick line issues. Fifth, a less complex logging while coring system has also been proposed in special cases to enhance and expedite real time decision making process in regard to proceeding to core cutting or not. Sixth, an innovative mode conversion system contributing to partial elimination of wireline jobs will also be proposed to substitute slick line/ wireline retrievals. Seventh, optimum tripping schedules have been characterized as crucial to match formation rock and fluid properties and type of WCC applied and also to prevent coring induced damage.
Subsea Blowout Source Control Technologies Utilized at the Macondo Accident and Developments in the Post-Macondo Era
Authors: Kutas David Thomas , Bailey Philip , Prohaska Michael
Published: March 2016

The publication generally and briefly describes what circumstances governed the petroleum industry and the connected regulatory organizations before the Macondo blowout. The paper shortly describes utilized classic containment and control efforts such as actuation attempts of the BOP, top kill with junk shot, relief wells. The publication's main focus is to describe and graphically present in detail the Cofferdam, the Riser Insertion Tube Tool, Top Hat, Capping Stack and choke and kill line collection method which were utilized to seal off the flow of hydrocarbons at the Macondo blowout. An extended literature review has been completed to fully cover and understand the technologies which were utilized and newly developed in the efforts to stop the outflow and abrogate the accident. The assessment of critical properties, problems are also presented next to the description of the specific source control technology. The blowout has triggered efforts never seen before both in short- and long-term not only from the side of affected regulatory and company side but industry wide. Short-term, the main effort was to contain the blowout as soon as possible, long-term it triggered strong determination from companies, and connected businesses to create proper contingency planning, containment technologies and strategies also through newly established consortiums. The non-profit oriented consortiums, containment systems and established HSE regulations need to be maintained properly even in a low oil price environment, so deeper understanding, recurrent inspection of the development ways of containment technologies in offshore environment can be crucial for sustaining the high HSE standards. The paper also aims to summarize knowledge to be able to make proper decisions in case of deepwater projects.
Taming the Beast: Consideration of Available Surface Power When Using a Modern, High-Specification Rig
Authors: Snowie Mike , Alemi Hassan
Published: March 2016

Modern Mobile Offshore Drilling Units (MODU) are equipped to ensure they are able to cope with the demands of both current and future offshore well design challenges which may be located in either in deep water or inmature basins like the North Sea thatrequire significant measured depths to reach the intended target. With all of this drilling power, such as topdrives capable of producing over 75,000ft-lbs of continuous torque and multiple mud pumps each with the ability to flow in excess of 1,000gpm it is readily possible to damange the wellbore by over using the available capacity of the rig. In reality this surfeit of available energy, if not used judiciously, can potentially result in unexpected problems.

Much has been written in the past with regards to ensuring that the available rig capability is best utilised to achieve complex well objectives and a great deal of the techniques developed in extended reach and complex well drilling operations were designed to make the most of the capacity available. Now, with high specification rigs these techniques identified originally in the early to mid-1990's, though still valid need to be used with care and consideration since the rig capabilities have advanced significantly such that without a degree of caution it is possible to cause significant damage to the downhole tools or wellbore and potentially loose either the section or the well altogether. Whilst many of the techniques often termed ‘good oilfield practice’ are still valid there are now additional considerations which have to be incorporated into both the well plan and the day-to-day operations on the rig to ensure that best use can be made of the rig's capability.

This paper aims to show how one operator successfully used a modern, high-specification jack-up rig to access a remote reservoir where challenging drilling conditions presented a number of potential obstacles to achieving the well objectives.
Effect of Rheology on Annular Sealing: From Placement to Failure
Authors: Lavrov Alexandre , Torsæter Malin
Published: March 2016

Wellbore integrity is a crucial aspect of well construction. The integrity of annular sealing has a bearing on the overall integrity of the well. The integrity of the annular seal is affected by the properties of cement (or sealant, in general), including its permeability, mechanical strength, bonding strength, chemical and thermal stability. Well integrity is also influenced by large defects introduced into the sealant during placement, e.g., gas channels caused by gas migration during setting, or mud pockets left undisplaced in washouts.

The displacement efficiency is a function of the mobility ratio of the fluid in place, e.g., the drilling mud, and the fluids being injected, such as the spacer and the cement. Rheological properties of the fluid in place and the injected fluids, the well inclination, and the geometry of the annulus have an impact on the displacement efficiency.

The effect of rheological properties of the injected fluid and the fluid in place (yield stress and the plastic viscosity) is evaluated in this study by means of numerical modeling. It is shown how a proper combination of the rheological properties can improve the fluid displacement from constrictions in the annulus, e.g., when the casing is not perfectly centralized in the borehole. It is also shown how an unfavorable combination of rheological properties and annular geometry may promote the development of gas channels and mud pockets in the annulus. Unless the borehole cross-section is perfectly circular, an unfavorable combination of rheological properties may lead to viscous instabilities during annular flow, resulting in mud channels left in the annulus. During lifetime of the well, such channels may become conduits for formation fluids. They also may serve as stress concentrators when in-situ stresses or wellbore temperatures are altered. Finite-element computations of thermal stresses near a channel left in the cemented annulus reveal that tensile stresses induced around such a channel by heating may be sufficient to create fractures in cement around the channel.

The methodology elaborated in this study enables prediction of cement integrity from placement to failure and thus spans the entire well lifetime.
Workflow for Optimal Injection of CO2 to Enhance Oil Recovery in Mature Oil Fields: A Preliminary Study for a Field Pilot Program
Authors: Alcorn Zachary P. , Fernø Martin , Graue Arne
Published: March 2016

Enhanced oil recovery (EOR) from mature oil fields presents unique challenges, as it requires well designed workflows for the injection of water, gas, or chemicals. Determining the optimal injection and production plan for mature fields can both maximize hydrocarbon recovery and reduce cost. This study proposes an integrated reservoir management workflow to improve oil recovery in mature oil fields in an ongoing field pilot research program. The workflow involves integration of traditional reservoir management methods with a real-time optimization approach. The early phase pilot research program management strategy is composed of several key components, including: improved reservoir characterization, generation of reservoir and simulation models, history matched simulation models, and development of a real time approach to optimize EOR reservoir peformance. The optimization strategy allows decision making at two different time scales: coarse and fine. At the coarse time scale, decisions are made about monthly injection and production rates over a time horizon from the decision making point into the distant future, aiming to optimize net present value (NPV). Various economic and technical constraints are included at both time scales. Field data from a conjoined five-spot well pattern, with two injectors and six surrounding producers, in a heterogeneous carbonate reservoir in the Permian Basin of west Texas is considered. Several realizations of a reservoir model were history-matched to field performance and subsequently used to predict and optimize future performance. The proposed workflow is being adopted within a current field pilot research program. The implementation of such a reservoir management plan allows operational decision making to be better informed and updated in real time. Assimilation of newly obtained data removes the cumbersome task of manually updating reservoir models to forecast field operations.
Four Years of Continuous Foamer Application in Southern North Sea Offshore Gas Wells
Authors: Vogelij Nico A. , Veeken Cornelis A. , Islamov Rafael I. , Lugtmeier Bert , Ros Oscar , De Vries Gert , Zhidkova Natalia A.
Published: March 2016

In the current brown field environment a lot of mature gas wells in the Southern North Sea (SNS) are liquid loading. Foamer can be injected in the wellbore as a gas well deliquification (GWD) measure to mitigate this liquid loading behavior. Foamer can be injected periodically in batch mode or continuously downhole by means of a small capillary string installed in the wellbore.

To date ONEgas* is producing 12 offshore gas wells located on 3 manned SNS platforms by means of continuous foamer (CF) injection. The first offshore CF installation came online in 2011 and dozens more installations are scheduled in the near future. CF has gone through a steep learning curve where the next step is to install CF on an unmanned SNS platform. After 4 years of gas production with CF a lot has been learned about designing, installing and operating capillary string CF installations.

This paper demonstrates the success of continuous foamer injection by showing increased production and recovery due to foamer but also presents the challenges that were experienced in terms of uptime i.e. poor reliability due to capillary blockages, sand erosion and surface facility upsets etc. The method of tackling these reliability issues to maximize uptime is presented, including an overview of the current and future subsurface and surface hardware components.

*ONEgas is a combined business unit of NAM and Shell UK
Advanced Big Data Analytics Improves HSE Management
Authors: Tarrahi Mohammadali , Shadravan Arash
Published: March 2016

Safety enhancement is the priority of every organization. Annually millions of dollars are spent to develop procedures and practices to diminish the health, safety and environmental disasters. Monitoring incidents and hazards and performing timely analysis leads to effective remediation efforts. In oil and gas upstream industry, a thorough understanding of HSE data and intelligent data analytics is essential to improve safety and particularly to reduce injuries and fatalities.

Most of the conventional HSE management and hazard identification systems are incapable of agile and automated data integration and smart decision making. Furthermore, HSE incident database is often too intricate to comprehend and its analysis is solely dependent on personal skills of individuals. In order to extract explanatory features' relationship and intelligently make execution strategies, a big data analytics platform is developed. This code enhances the value and quality of information entered into the HSE management systems, consequently prevents occupational hazards and results in a safer workplace. This smart platform quantifies the associated risk with every HSE decision. Oil and gas industry incidents based on area, data type and case were queried from the big data database.

This algorithm was executed on a large public industry data base of occupational injury and illnesses to enhance big data HSE management. This code explored 3 million records categorized based on several parameters including super sector (major industry), industry (sub sector), data type, case type (data sub type), area (i.e. states), year. This paper exemplifies the value of advanced big data analytics to improve safety leadership. Capturing and analyzing such extremely large datasets is impossible with traditional methods.
Machine Learning Leads Cost Effective Intelligent Fluid Design: Fluid Engineering Perspective
Authors: Shadravan Arash , Tarrahi Mohammadali
Published: March 2016

What is the catch for intelligent fluid design? Several hours of laboratory testing (some successful, some unsuccessful), dealing with various complex chemistries, listening to multiple people, as long as they are around, some of whom educated with the science called Chemistry rationalizing and trying to match the theories with the laboratory results? Getting superstitious about the physics of the problem due to lack of data? Dealing with contradictory data, and convincing ourselves, engineers, that this is the way to go? Seeing laboratory personnel taking pride on the number of the tests that have conducted while we still need to conduct more testing to determine the next additive concentration for the new well with different downhole condition? Facing with enormous non-productive time and dealing with the fear of failing to deliver to the job and lose the tender, on the service side, or choose the most cost effective scenario for your well, on the operator side? Or shall we go with what Joe proposed and reduce the risk? He has been there for years. How much more testing is enough for a known system, area or formation?

Chemists are creating better and novel formulations, and laboratory personnel are doing their job following the API, ideally around the world, but fluid engineers are still testing or manage testing the fluids by trial and error whether in fracturing, cementing or drilling fluids. While designing fluids by trial and error in each fluid research group might sound unrelated to the other, all have one in common because of the traditional approach in fluid design. Trial and error testing lacks the vision for sustainable fluid knowledge management and intelligent design.

The purpose of this paper is to challenge the status quo in fluid design, discuss what is missing in stepping towards intelligent fluid design and identify the challenges and limitations to execute the proposed method. Disadvantages of the traditional fluid designs, lack of knowledge/data management or sharing and the cost incurred are elaborated. Machine learning algorithms lead as the prime solution for intelligent fluid design, saving thousands of hours of laboratory testing, efficiently integrating sizable experimental database and optimizing the operational cost and delivery.
A Holistic Approach to Sand Control
Authors: Maclachlan S. , Harper C. S.
Published: March 2016

In an age of low cost oil with increasing lift costs, the challenge is to exploit and drain existing reservoirs as cost effectively as possible. Completion failures can be a major source of expenditure if not designed correctly, leading to unnecessary costly workovers or interventions in conjunction with deferred production. By using just a fraction of the existing available data in a structured and consistent manner allows selection of the optimum completion design. What must be included in a workflow to address this challenge?

The objective of this paper is to explain how a multi-discipline approach incorporating, geochemistry, production chemistry, production technology, and reservoir engineering can be applied and how the disciplines can interact with and complement each other. The resulting process is a robust structured workflow that can lead to significant improvements in sand control design and selection.

More time spent planning and designing lower completions as part of an integrated system can result in significant benefits to the operating company. The completion can be optimised resulting in an improved completion lifespan, lower CAPEX and OPEX costs and increased production volumes over the life of the field, while also taking into account environmental considerations.

This holistic approach has been incorporated into several field development plans and individual well completion designs on behalf of operators around the world.
Impact of New and Ultra-High Density Kill Fluids on Challenging Well-Kill Operations
Authors: Rinde T. , Killie R. , Howard S. K. , Solli L. , Lillelokken N.
Published: March 2016

Whilst significant efforts have been made worldwide on developing solutions for capping offshore blowouts, less has been done to ensure safe and reliable kill operations through a relief well. This paper presents new solutions to challenging kill operations.

Well-kill operations through a relief well are still considered the most reliable and ultimate method for killing a blowing well. Strict legislation has been enforced for such operations, which challenges technical operational limits and margins. The requirement to be able to dynamically kill a blowing well through one single relief may restrict well design and thereby reduce contingencies.

By pumping of ultra-high density kill fluid (UHDKF) or by injecting a slug of UHDKF as part of a staged well-kill operation, more reliable operations can be planned for with reduced pumping pressures, reduced horsepower requirements, significant fluid volume reductions and cost reductions. Furthermore, these ultra-high density fluids can enable kill operations that would otherwise require changes to the original well design.

Some ultra-high density kill fluids have been formulated based on high density cesium brines. A clear brine with a density of 3.20 g/cm3 and very low viscosity has been formulated by blending cesium phosphate and cesium tungstate brines. Higher densities can be achieved by adding a small amount of solid weighting material to cesium brines.

The new ultra-high density kill fluids represent a great technological step. It is recommended that the findings presented in this paper are implemented in future Blowout Contingency Plans in order to ensure sufficient operational margins in the relief well planning and the kill programs.
Thermal Effects on Subsea Wellhead Fatigue During Workover Operations
Authors: Sevillano L. Cantinelli , De Andrade J. , Sangesland S. , Stanko M.
Published: March 2016

Intervention and workover operations can significantly impact the structural integrity of the subsea wellhead system with regard to its fatigue life. The increasing frequency of these operations has called for a renewed focus on the fatigue capacity of subsea wells, which has greatly improved the overall methodology employed for wellhead fatigue analysis during the life cycle of the well. However, thermal effects along the well have yet to be incorporated. This paper addresses this issue by analyzing the wellhead fatigue damage during a workover operation considering the thermal effects.

Injecting cold fluids in previously producing wells will cause the temperatures along the well to shift from a steady profile to a transient one, resulting in lower temperatures along the well throughout the workover operation. In this work, this effect has been incorporated into the wellhead fatigue analysis method issued by DNV by determining the temperature along casing strings, cement layers, annuli and tubing. Further, these temperature profiles are input into a 3-D finite element model of the wellhead system. Numerical simulations were performed for different temperature profiles, corresponding to distinct moments during the workover operation. Resulting load-to-stress curves of fatigue hotspots were combined with external load time histories to estimate fatigue damage rates.

Stresses at wellhead fatigue hotspots seem to be influenced by the way in which contact forces are shared between the different structural components of the wellhead, particularly by the surface housing and the conductor housing. It was observed that the response of the tubular string inside the well towards variations of their temperature profiles, and top of cement (TOC), may cause the estimates of fatigue damage rates to change. Results indicate that the impact of thermal-related loads on the assessment fatigue damage rates is very dependent on the surface casing top of cement, being highest as the TOC approaches the mudline level.

Notwithstanding the large body of research on wellhead fatigue, thermal loading and its effects on fatigue damage rates have yet to be thoroughly investigated. By incorporating the cooling of the well during intervention operations into the fatigue analysis it was possible to assess more realistically the fatigue damage of the wellhead and obtain reduced fatigue rates for some wellhead configurations.
Reducing NPT of Rigs Operation through Competency Improvement: A Lean Manufacturing Approach
Authors: Basbar Ashraf E. , Al Kharusi Ahmed , Al Kindi Abdulbaqi
Published: March 2016

From a drilling contractor point of view, drilling operation should be always at least on schedule and on budget. However, drilling in challenging environments with different drilling problems (technical and un-technical) causes a lot of non-productive time (NPT), i.e. time where the rig is not drilling, which pushes drilling operation behind the schedule and results in a lot of money lost. However, the new low oil price environment put a pressure on drilling contractors to focus on improving drilling efficiency and to be more innovative in reducing NPT during drilling operations; knowing that costs arising from NPT typically account for about 10% to 15% of total drilling costs, and can rise as high as 30%. In another words, drilling contractors will have to learn how to operate differently in order to weather the low oil price environment. The authors strongly believe in today's climate, lean manufacturing methodologies could offer the sought solution. Essentially, lean is a way of thinking centred on locating and eliminating unseen or unnoticed ‘waste’ occurring across the entire drilling operation.

This work in hand demonstrates how the concept of lean manufacturing can be applied to reduce NPT of drilling operations. In this paper, drilling time for 6 workover and 3 drilling rigs has been analysed. A Pareto chart was used to analyse the NPT which accumulated to 27.6% in order to know the most common (highest occurring) sources of such NPT. The crew competency represented 42% of the total NPT, followed by 27.6% due to mechanical equipment failures, while wait on material accumulated to 17.2%, the operational equipment failures summed 12.7% and finally accommodation scored 0.5%. Next Ishikawa (fishbone) diagrams has been utilised to show the causes of imperfection in crew competency to identify these sources of variation.

The analysis revealed areas of immediate intervention such as crew competency program and work related performance incentives. Therefore, training programs were created and work performance related promotions were introduced. Simply, authors believe these countermeasures have focused on causes behind how crew behave, which is the most difficult challenge of all. As without the proper behavioural principles and values, lean methodologies will be totally misapplied and fail to deliver results.This has resulted in 0% NPT materialised within 3 months only of implementing LEAN manufacturing methodology in drilling operation.In this paper, the LEAN methodology reveals an important tool which is able to find simple and effective solutions to the problems encountered in operations such as lack of performance and waste of time.