bluuebunny/crossref_metadata_2025 huggingface dataset:
An Integrated MEOR Project; Workflow to Develop a Pilot in a German Field
Authors: Alkan H. , Biegel E. , Krüger M. , Sitte J. , Kögler F. , Bültemeier H. , Beier K. , McInerney M. J. , Herold A. , Hatscher S.
Published: June 2014

The workflow and the results of the work packages of a Microbial Enhanced Oil Recovery (MEOR) project aiming at a pilot are introduced and discussed. An enrichment culture consisting of a community of various microbial species derived from one of the Wintershallfields shows good growth and EOR characteristics upon nutrient stimulation tailored for the given reservoir characteristics, including high salinity (160000ppm). The emulsification indices as well as measured interfacial tensions (IFTs) between dead oil and the microbial culture supernatant collected during the exponential and stationary growth phases indicate potential beneficial impacts on capillary forces. Imbibition experiments with Bentheim sandstones support the measurements. The rheology of cell-free medium after growth shows pseudoplastic behavior resulting in viscosities of up to 3-6mPa•s at representative shear rates. An important EOR effect was gas (CO2) generated during growth, which resulted in a calculated reduction of 3-4mPa•s in oil viscosity. The effect of pressure (reservoir pressure is 30bar) on the metabolite generation is being investigated with growing cells in high-pressure bio-reactors. Model systems including micromodels, sandpacks and corefloods were used under sterile and anaerobic conditions to monitor the oil displacing effects of the nutrient-stimulated communities. Experiments using polydimethylsiloxane (PDMS) micromodels consisting of channels with different pore sizes indicated an improvement of the sweep efficiency potentially due to selective plugging. A sandpack system was designed to test the dynamic performance of the bacteria and proposed nutrient formulations. The flooding tests performed under reservoir temperature showed incremental oil of up to 18% of OOIP after three successive medium treatments. The oil recovery performance of the proposed nutrient formulations is also being tested with coreflooding experiments at reservoir pressure and temperature. Numerical simulation work packages focused on modeling all MEOR components as tracer in oil and water phases and implement growth/decay of bacterial cells by Monod equation. The implementation of this concept into the commercial reservoir simulator STARS/CMG using its reaction kinetics option is ongoing. Polymer and surfactant effects in water phase and gas generation effect on oil viscosity are modeled using standard approaches. The parameters are calibrated with batch as well as dynamic growth experiments. The implementation was validated by comparison to data obtained from sandpack and coreflood experiments. Results of both experimental and numerical work packages indicated additional oil recovery due to selective plugging, emulsification, CO2 generation and beneficial viscosity changes of water and oil phases.
An Interim Case Study of an Alkaline-Surfactant-Polymer Flood in the Mooney Field, Alberta, Canada
Authors: Watson Andrew , Trahan Gregory A. , Sorensen Wayne
Published: June 2014

Chemical Enhanced Oil Recovery (CEOR) use is expected to increase as more production companies implement tertiary oil recovery methods. This case study provides an outline of the process used to determine the applicability of an Alkaline-Surfactant-Polymer (ASP) flood, how the ASP chemical package was selected and tested, and the current field trial status. The selected field for this project is the low temperature Mooney field in north-central Alberta, Canada, producing ~16° API gravity oil with a viscosity of 150 to 1,500 mPa-s from the Cretaceous Bluesky sand formation at a depth of approximately 900 meters.

In 2006 a waterflood pilot test recovered an incremental 3% of the original oil in place (OOIP) over the primary production recovery (~4 to 5%). A three well polymer-only pilot was started in 2008 for 14 months and showed a total recovery of 18% OOIP suggesting a tertiary recovery method could be more successful than a waterflood. An independent laboratory tested multiple ASP packages, formulated with various surfactant types, either NaOH or Na2CO3 as the alkali in softened injection water, and with a partially hydrolyzed copolymers of acrylamide and acrylic acid. This independent reservoir screening identified several ultra-low interfacial tension ASP chemical package candidates, and core flooding confirmed increased oil recovery. Low chemical concentrations were specifically tested to minimize ASP chemical costs and downstream issues with emulsions. Economics were promising enough to proceed with company and Canadian approvals for ASP Phase One field implementation. Commercial injection began September 2011.

The Phase One ASP scheme consists of 25 injectors and 26 producers. Production from the ASP flooded area increased from approximately 175 barrels of oil per day (BOPD) in summer 2011 to a current high of ~2600 BOPD in December 2013, a period of 30 months. ASP chemical injection is continuing. Some injection delays have been caused by operational issues (water source and pipeline/facility modifications). These promising oil recovery results allowed Phase Two to be approved, and it is slated to be completed in 2014. Phase Three development is in the planning stage including drilling 16 additional primary horizontal wells.

The ASP flood of the Mooney field is a multi-well ASP flood that is progressing well but is still in the preliminary stages of data collection. The reservoir will continue to be monitored over the coming years to develop a comprehensive analysis of the tertiary oil recovery and how it compares with the initial laboratory ASP test results and predictions.
Operational Aspects of a Biopolymer Flood in a Mature Oilfield
Authors: Ogezi Oja , Strobel Joachim , Egbuniwe Daniel , Leonhardt Bernd
Published: June 2014

Bockstedt, a mature oilfield in Northern Germany, was discovered in 1954 and put on-stream in the same year. The waterflooding of this high permeability Valanginian sandstone reservoir, with moderately viscous oil and highly saline brine was started in 1959 and continues to date, albeit at a high watercut. A compartment within this field was selected for a pilot test of the biopolymer Schizophyllan; a polysaccharide, with considerable viscosifying efficiency and high salinity and temperature stability.

As the biopolymer flood progresses, surveillance and monitoring techniques that estimate in-situ polymer properties and help to understand the influence of the polymer on reservoir performance are applied. Operational procedures have also been developed and tested to ensure a manageable restart of operations in the event of planned and unplanned well shut-ins. Production logging test runs in the injection well during the water injection phase showed a homogeneous injection profile over the reservoir interval. Well logs from new wells drilled within the pilot area provide additional insight with regards to the saturation distribution. Passive and partitioning tracers have been injected and are regularly being sampled and analysed.

After a successful polymer injectivity field test was conducted in mid-December 2012 for Schizophyllan, continuous polymer injection commenced in early January 2013. High-resolution data available from permanent downhole gauges show an initial increase and subsequent stabilization of bottom-hole pressure at a higher value in the injection well after the start of polymer injection. A modified Hall plot used to assess the polymer injectivity does not show any significant reduction in injectivity. An estimation of the reservoir properties during the water injection phase and subsequently the in-situ effective polymer viscosity during the polymer injection phase using several falloff tests confirms that, the polymer is not shear degraded in the reservoir and offers insight as to the position of the polymer front in the reservoir. The work was accompanied by numerical simulation to better understand the in-situ rheological properties of the polymer.

This paper discusses the challenges, experiences and early results from the polymer flood pilot operations in a mature oilfield after an early technical evaluation.
Polymer Flood of Viscous Oils in Complex Carbonates
Authors: Doorwar Shashvat , Mohanty Kishore K.
Published: June 2014

Polymer flooding is investigated in laboratory cores as a non-thermal enhanced oil recovery process for viscous oils in heterogeneous carbonate reservoirs. Core floods were performed in vuggy dolomite cores saturated with 200 cP crude oil and complementary pore-scale investigations were conducted using 2D glass micromodels. Tertiary polymer floods conducted after waterfloods of a viscous oil recovered more oil than secondary polymer floods in vuggy dolomite cores as well as Berea cores. This was also observed in oil-wet dolomite cores. The oil recovery in secondary polymer floods decreased as the polymer viscosity decreased. The secondary polymer flood, of course, recovered the oil faster than tertiary polymer floods. The oil recovery was also lower and slower in oil-wet cores compared to water-wet cores. Micromodel experiments showed that the spacing between viscous fingers increases as the viscosity ratio increases. The viscous oil bypassed in waterfloods is mobile and can be recovered by a polymer flood. The waterflood recovery in a micromodel with connected heterogeneity was low, but the tertiary polymer flood recovered a significant amount of oil. Water imbibed into the low permeability bypassed regions and pulled the oil into high permeability regions which was later recoverd by the polymer flood. There was also no imbibition in oil-wet micromodels where the oil recovery was lower and slower compared to water-wet micromodels.
Magnus WAG Pattern Optimization Through Data Integration
Authors: Erbas Demet , Dunning Matthew , Nash Timothy M. , Cox David , Stripe John A. , Duncan Euan
Published: June 2014

This paper focuses on studies carried out to explore possibilities to improve both areal and vertical sweep efficiency in mature WAG patterns in the Magnus oil field. Magnus tertiary miscible gas injection started in 2002 through a WAG scheme taking the recovery factor close to 56% to date at a very high net efficiency of 3.5 mscf/stb. Pore scale sweep efficiency is very good with 8% residual oil to miscible gas flood (Sorm) based on core flood data. However, areal and vertical gas sweep efficiency seems to be sub-optimal based on 4D seismic and PLT data.

The Magnus Sandstone Member (MSM) consists of a number of stacked turbidite sand lobes separated by intra formational shales with varying thickness and lateral extent. The WAG scheme has been operated and managed by considering the MSM as a single reservoir unit. As the patterns have matured, it has become apparent that the scheme could be optimized by further vertical separation of the reservoir units. Key surveillance data such as 4D seismic monitoring gas movement, PLTs from both producers and injectors, well performance and open hole saturation logs have been coupled with simulation to study options for vertical and areal sweep improvement. These options involve changing sweep direction and intervals by means of adding new perforations and shutting off zones, complete reversal of the patterns – i.e. converting producers to injectors and vice versa, and use of chemicals for flood diversion.

Evaluation of multiple options resulted in a phased WAG optimization programme of which the first phase in the Central Panel is being proposed for execution in 2014. This phase involves changing perforation intervals in both producers and injectors. Later phases consist of further changes in perforation intervals, potentially pattern reversals and use of chemicals for diversion. A behind flood front core is planned in 2015, which is expected to help calibrate the optimization programme by quantifying Sorm and the degree of vertical sweep achieved in the field. The study required a detailed review of the surveillance data from various sources including 4D seismic and PLT data which were crucial in understanding the sweep efficiency. Relatively low cost options were identified to improve the sweep as opposed to drilling new wells. Integration with the operations team was the key in creating a business case for pattern optimization on a 30-yrs old, bed space constrained platform.

The workflow of this study and the learnings are applicable to mature patterns in any WAG EOR scheme. Optimizing the WAG patterns enables more efficient use of the available gas, which (given that the cost of gas is a significant component of any gas injection project) makes this more commercially viable and cost effective tertiary recovery option.
Safety Considerations for Air Injection into Light Oil Reservoirs
Authors: Fassihi M. R. , Moore R. G. , Mehta S. A. , Ursenbach M. G.
Published: June 2014

The presence of oxygen and carbon dioxide in the injection and production streams of any high pressure air injection (HPAI) project or the high oxygen partial pressures associated with enriched air/oxygen injection projects may create serious safety concerns such as potential of explosion or corrosion. Compilation of field problems and reported solutions from such projects indicate that no insurmountable problems exist in the implementation of high pressure air injection projects. Generally, the operators have successfully implemented safe operations when injecting at pressures as high as 6,000 psi. The long term successes of the HPAI projects in the Williston Basin which were initiated in 1978 by Koch Industries, Inc. and continue to be operated today by Continental Resources, Inc. have confirmed that HPAI is a viable and safe process for recovering light oils.

A number of oilfield oxygen injection programs have also been undertaken since the early 1980's when Greenwich Oil operated the first oxygen injection project at Forest Hills, Texas. In Canada during the 1980's, oxygen was injected by BP/AOSTRA at Marguerite Lake, by Dome Petroleum at Lindberg, by Husky Energy at Golden Lake, by Mobil Oil at Fosterton, and by Gulf Canada at Pelican. In the U.S. oxygen injection pilots were operated by ARCO in the Holt Sand Unit, Texas and more recently by NiMin Energy at Pleito Creek, California.

With increased oxygen partial pressure, there is a greater chance of safety or corrosion problems. In fact, the high oxygen content associated with the Holt Sand Unit project in West Texas caused a severe energy release that resulted in test termination. The reported data on this field are scarce and the nature of energy release has not been discussed in detail. This paper will first discuss some important details on the Holt Sand Unit (HSU) oxygen injection pilot and, then, will provide an overview of the key learnings from this project. The reasons behind the energy release in the HSU project will be discussed using the surveillance data, combustion tube test and numerical modeling results. Operational aspects during and after the test termination will be discussed. This information should provide a better understanding of the safety aspects of oxygen handling and proper practices in such operations.
Assessment of Three Phase Relative Permeability and Hysteresis Models for Simulation of Water-Alternating-Gas WAG Injection in Water-wet and Mixed-wet Systems
Authors: Shahrokhi Omid , Fatemi Mobeen , Sohrabi Mehran , Ireland Shaun , Ahmed Kamran
Published: June 2014

Obtaining reliable relative permeability (kr) values and their variations is difficult particularly in processes involving three-phase flow and flow reversal (e.g. WAG injection) which results in kr hysteresis. The current approach in the industry is to use a three-phase kr correlation (e.g., Stone I, Stone II, Baker) in conjunction with a kr hysteresis model (e.g., Killough, WAG- Hysteresis). However, these models have been mostly developed based on water-wet systems and have rarely been benchmarked against experimental measurements.

In this paper, we present the results of an extensive assessment of different three-phase relative permeability models available in the most widely used reservoir simulators. The input two-phase data needed for using three-phase kr correlations were obtained from core flood experiments. The simulation results were directly compared with WAG injection experiments performed under both water-wet and mixed-wet conditions.

The results show significant differences between the simulation and experimental results of WAG injection. In water-wet rocks, the results show that without considering kr hysteresis, Stone-I model underestimates WAG performance, but it overestimates oil recovery in mixed-wet rocks. SWI and Baker correlations overestimate WAG performance in water-wet rocks while for mixed-wet rocks they significantly underestimate production data. For both wettabilities, Stone-II significantly underestimates oil production. The generated recovery trends by IKU model show a relative advantage over other models but still underestimates the performance of WAG injection especially for later cycles.

Coupling of three-phase kr correlations with hysteresis models (Carlson, Killough and Jargon) generally results in highly overestimated oil recovery predictions especially for mixed-wet conditions. For water-wet systems, coupling Stone-I with WAG-hysteresis model improves the predictions up to the second gas injection period. Nevertheless, serious underestimation is observed for further cycles. The WAG-hysteresis model overestimated WAG performance in mixed-wet systems. To improve its prediction, based on our experimental results, WAG-hysteresis model parameters were adjusted after each cycle. This modified approach improved simulation results in water-wet systems. However, none of the available approaches could adequately reproduce experimental results obtained for mixed-wet conditions. This is a major concern for predication of WAG performance in real reservoirs which are believed to be mixed-wet.
Pressure and Rate Rebalancing to Improve Recovery in a Miscible CO2 EOR Project
Authors: Linroth Mark A. , Rickard Andrew E.
Published: June 2014

In a CO2 EOR project the injected CO2 seldom sweeps all portions of each injection pattern uniformly. This is compounded by the fact that injection patterns are not always symmetrical and the injector itself may not be centered within the pattern. Areal sweep within a pattern is further influenced by pressure gradients which may not be uniform in all directions.

At the SACROC unit the approach to maximizing the areal sweep involves detailed monitoring of individual producing well pump intake pressures and producing GOR's as well as the calculated streamlines to identify opportunities for changing the direction of CO2 migration in the reservoir. It is frequently observed that response to CO2 injection occurs in only one well or on only one side of a pattern with little to no effect in the other directions. The remedy presented in this paper involves converting to flow or slowing down the pump in the responding wells (and thus raising the pump intake pressure) when their GOR exceeds a certain threshold and upsizing or speeding up the pumps in the wells on the opposite side of the pattern.

The effect of these changes is to alter the pressure distribution within the pattern and change the portion of the reservoir being processed by CO2. We have documented cases where the pattern recovery has more than doubled due to altering the streamlines in this manner. This technique of monitoring and altering the streamlines is time and data intensive but in the patterns where it is applicable significant increases in the ultimate EOR recovery can be obtained for essentially zero capital cost.

This paper discusses the pattern selection criteria, data requirements, and the timing and method of adjusting the withdrawal rates to alter the streamlines and increase areal sweep efficiency.
Analyzing The Benefits Of Utilizing 360° Panoramic Photo Survey Technology On A Shell Offshore Platform
Authors: Berger P. E. , Matsuura J. P. , Barrios A. , Hopkins P. , Wagner M. T. , Weston M.
Published: June 2014

Shell's Enchilada offshore platform has been surveyed in September 2012 with a specially built, fully automated 100 megapixel 360° HDR panoramic photography camera system with 3D measurement capability. Subsequently, a 360° PanoramicGuide web-based viewer was produced and made available to Shell users. The spherical photos were indexed to the facility's general arrangement drawings. Interactive descriptive menus and maps were made available to quickly locate and navigate to points of interest. Users can choose from multiple viewpoints of the Enchilada facility, view 360° in all directions around those viewpoints to virtually examine various areas/equipment in the platform, zoom in to view precise detail, and take 3D measurements between visually recognizable shapes and patterns from the viewpoints.

The paper will discuss a number of potential and tested applications, the latter where the technology has been used for the Enchilada platform:

Detailed visual assessments for engineering design, project planning, operations and safety reviews; Visual reference during conference collaboration meetings with offsite subject matter experts and email communications to assure common understanding; Visual assessments by subject matter experts, including consultants and sub-contractors that are not possible with video, standard photography or 3D models/images created from laser scans alone.

Experience using the viewer has demonstrated that users are able to improve quality and collaboration in planning work related to construction and modifications, potentially resulting in decreased cost and project recycle, improved HSE and reduced liability and risk, by minimizing or even eliminating offshore trips and time on site for vendors and other personnel. Development of new advanced visualization and communication technologies will be a key success factor for future improvements in planning, asset management and Integrated Operations, among other remote operations activities.
Micronized Ilmenite - A Non-damaging & Non-sagging New Weight Material for Drilling Fluids
Authors: Al-Bagoury Mohamed
Published: June 2014

Ilmenite (FeTiO3) was first introduced as a weight material in the North Sea area in the early 1980's. The quality of ilmenite suitable for drilling fluids was continuously improved to meet the drilling criteria. Ilmenite as a weight material offers many benefits over API barite such as high density (4.6SG), mineral hardness (6 Mohs), low heavy metals content, acid solubility and sustainability due to the large reserves.

Currently there are certain drilling areas such as narrow pressure margin wells, HPHT wells, deep water, ERD, and slim hole, where API barite may not offer the required performance. For those wells a controlled rheology and minimal sag is the key to success and a specialty weight material can provide this. To fulfill such needs a micronized ilmenite grade (5μm) has been developed for use as a weight material for drilling fluids. The paper will show the testing of the new grade in both aqueous and non-aqueous drilling fluids. High temperature dynamic sag and filtration results will be presented. Acid solubility in hydrochloric acid will be highlighted. The new grade shows excellent dynamic sag, stable rheology and high acid solubility, which are very useful for many drilling operations particularly deep offshore drilling. On a top of the high performance this new advanced material is a cost-effective solution for some of the high costly drilling challenges.
Failsafe Polisher for Produced Water Discharge
Authors: Rodeman Lance , Stamp Nick
Published: June 2014

Deepwater production facilities in the Gulf of Mexico (GoM) and other regions periodically experience short intense upsets of their produced water treatment. These upsets are due to many factors inherent in their geological formation and physical location:

Hydrate formation and associated chemical dosing procedures (LDHI, Methanol, etc.) Frequent startup/shutdown of production wells due to weather threats, new wells, tiebacks etc. Large motions on board the platform from adverse weather conditions Frequent rate changes in fluid production (slugging, debottlenecking)
Improved Zonal Isolation in Open Hole Applications
Authors: Bårdsen Johnny , Hazel Paul , Vasques Ricardo R. , Hjorteland Øyvind , Eikeskog Øystein
Published: June 2014

Achieving effective zonal isolation within long reach horizontal wells via conventional means, such as cement or swell packers, is becoming increasingly challenging to the industry. The longer step outs limit the Equivalent Circulation Density (ECD) due to frac/pore pressure limitations. Subsequent complex stimulation operations impose higher differential pressure (dP) across the packers.

To address these challenges, a novel design was introduced, effectively creating an expandable metal, sleeve-type annular barrier that allows cementless completions and effective zonal isolation. The design of the new annular barriers, assembled on a full bore liner, minimizes the running outside diameter (OD) whilst delivering a high differential pressure seal even within a washed out hole.

The qualification process was designed to meet the International Organization for Standardization ISO14310 V3 standard and to simulate the lifecycle of the packer during acid stimulation and later-life water management.

The benefits to operators include increased reliability and certainty for success, both in the short-term and over the life of the wells.

This paper reports recent implementation of the new annular barrier to meet the unique challenges of annular high pressure containment. Findings are supported by specific case examples, and the paper includes a discussion on design, application and performance.
Well Collision Detector
Authors: Walle Eirik , Instanes Geir
Published: June 2014

The ClampOn DSP Well Collision Detector is a real time ultrasonic monitoring system for detection of a drill bit in the proximity of existing wells. The system provides real time data during drilling and thus supplements collision risk analyses and positioning data. The monitoring system lends from ClampOn's well-proven series of ultrasound sensors for sand monitoring, PIG detection, and leak detection. The working principle of the Well Collision Detector is discussed briefly. An application example from a drilling operation is shown to illustrate the utility of the system.
Subsea Inspection of Vibration and Acoustic Noise
Authors: Nysæter Kjetil
Published: June 2014

Statistics tells us that 21% of all topside pipework failure in the UK sector is due to vibration-induced fatigue, whilst erosion and corrosion stands for 13% (Figure 1). This is not directly comparable with the subsea world. Still, we now know that aging subsea pipework and structures suffer from fatigue, in many cases caused by vibration. The number one cause of vibration-induced fatigue is flow line induced vibration (FIV). Advanced simulation and modelling are used when designing subsea structures and subsea pipework to ensure that the design minimizes the risk of harmful vibration occurring. Simulation and modelling does not fully reflect real conditions due to the complexity of the pipework in combination with the unpredictability of multiphase flow regimes. Therefore, these models are usually very conservative, with a significant safety margin built in. In some cases, this may lead to a "permitted production rate" that is less than is safely possible. Installation of permanent or temporary vibration monitoring is the only way to be sure what the actual state is. Data from instrumentation is useful for several reasons. Firstly, because it provides actual displacement/acceleration data at any given frequency and this is directly related to the rate of fatigue. By post processing raw data together with modelling, it is possible to estimate what the vibration is at locations downstream or upstream of the instrument. Secondly, by further analysis of the raw data the models can be "calibrated" to give more accurate fatigue estimates.
Development, Test and Offshore Use of a Fouling Repellent Coating for Plate Heat Exchangers
Authors: Bischoff C. , Poulsen T. , Søhoel H. , Holberg S.
Published: June 2014

Fouling of top-side equipment is a common but non-trivial challenge in oil production. Especially offshore, where servicing is costly and time consuming, technologies to prevent or reduce fouling is wanted. For plate heat exchangers (PHE), fouling, of both organic (e.g. wax deposits) and inorganic (e.g. limestone scaling) nature, is capable of reducing the performance of the PHE to a state where on-shore servicing is required, in just six months.

We here present the development and test of a coating system, coined CORE Coat 010, which has demonstrated excellent results in the prevention of fouling formation on titanium PHEs used in offshore crude oil processing. The coating is a Sol-Gel derived glass ceramic organic:inorganic hybrid system. Given the glass ceramic nature, the coating system exhibits efficient thermal conductivity, is highly flexible, very wear resistant and only 5 µm thick.

From initial laboratory scale tests to full scale application on complete PHE units for offshore operation, the coating has demonstrated excellent stability in crude oil contact, minimal impact on heat transfer and an excellent ability to repel fouling that would otherwise hamper operation. To date, the longest operating PHE has been in position for approx. 1000 days, compared to approx. 180 days for non-coated units, operated under similar circumstances. Besides the use on crude oil PHE's the coating technology may be applicable in other crude oil processes where fouling is an issue.
Remotely Activated Completion Technology Improves Wellbore Productivity
Authors: Harestad Fredrik , Forsyth David , Adam Malcolm
Published: June 2014

The Command Activated Sandface Valve (CA-SFV) was developed to significantly improve productivity by enabling improved wellbore clean-up, particularly in extended reach and open-hole completions. Inefficient wellbore clean-up of highly deviated completions is common in production wells. Current solutions include smart well technology or time consuming clean up procedures that are both expensive and difficult to implement, leading to loss in well productivity, restricted access to reserves and in some cases a requirement to sidetrack the well.

A UK operator had observed no flow from the toe of one of its wells, while experiencing high drawdown at the heel section due to the dominance of high productive intervals. This threatened the economics for the overall field development. The CA-SFV was developed based on this operator's requirement to bring a high level of control over how they selectively cleaned up and flowed the reservoir sections. The key objectives of the valve were to allow sequential clean-up of the reservoir section from the toe to the heel without intervention or incremental rig time. Each valve had to be remotely activated by a pressure recognition signal and also had to deliver the mechanical functionality of a sliding side door for future water shut-off capability along the well bore.

Development of the valve was closely monitored by the operator including a technical assurance review and failure mode and effects analysis process. The result is a successfully field proven completion tool and a new completion technique for a more optimal production regime and increased oil recovery. The increased production and recovery from using this technology made the field development economically feasible. The Sandface Valve technology has now seen well over 100 installations with a functional 100% success rate.

Based on these successful installations, the remote technology platform has been developed further to allow this remote activation technology to become applicable for other common well applications.
Evaluation of Coordinated Control During Back Pressure MPD Operations
Authors: Siahaan Hardy B. , Vefring Erlend H. , Nikolaou Michael , Gravdal Jan E.
Published: June 2014

Automatic control becomes increasingly important to assist drilling operations. Basically, the first stage of designing an automatic control for a simple system is by selecting a variable to be manipulated and a variable to be controlled in the system. A drilling rig has a large number of variables. This makes the design of automatic control more complex due to the number of variables. Here, we discuss three ways of dealing with ‘multivariable control’ design and evaluate them by simulation studies.

The first approach is by designing a control system to coordinate all different variables in a centralised way. The second approach is by dividing the system into subsystems, each of which has fewer variables. A control system can be designed independently for each subsystem provided that the interactions between different subsystems are small. The third one is combination between the first and the second approach.

The three different approaches of design are compared for coordination of variables in MPD. When drilling with narrow pressure margins, back pressure MPD is often used with the choke being manipulated to control the BHP. It is of interest to evaluate the possibility of having additional variables like pump rate and back pressure pump rate as manipulated variables. In particular, for the design using centralised approach we consider the model predictive control (MPC) while for the decentralised approach we consider a class of PI control. For the third approach we design internal model control (IMC). We focus on drill pipe connections where we need to control the BHP and the gel breaking simultaneously.

The design of MPC depends on a predictive model and the tuning of its parameters which can be challenging. However, MPC has an attractive feature where it is easy to include constraints in the computation. IMC has the advantage of simplicity and ease of tuning compared to MPC. The drawback of IMC is that we need to compute an inverse of a model representing our system which can be cumbersome when the dimension of multivariables increases. While the design of PI control is the simplest one, we have to observe that the interaction between the subsystems should not be critical for a certain period of time during drilling operations. The results improve our understanding of the possibilities and challenges of introducing automatic control to drilling operations.
CO2 and NOx Emissions From Cuttings Handling Operations
Authors: Saasen A. , Jødestøl K. , Furuholt E.
Published: June 2014

Drilling operations at a new oil and gas field will produce a significant amount of drilling waste. In the Norwegian part of the North Sea, oil contaminated cuttings have not been discharged to sea for the last 20 years because of the OSPAR requirement for max 1 % oil on cuttings. The most frequently used option when drilling with oil based fluids is to send cuttings onshore for treatment. The affiliated volumes of hydrocarbons are distilled off using different methods. On older fields it is not uncommon to recomplete a well to become a waste reinjection well.

In the later years, technology has been developed to treat oil contaminated cuttings to below 1 %. This technology has been in use on drilling rigs on the UK shelf for several years, discharging cuttings from exploration wells drilled with oil based fluids. The technology for cuttings cleaning has been improved in later years, and several operators in the Norwegian sector are now investigating the possibility for cleaning and discharge of drill cuttings when using oil based drilling fluids. The three options for handling oil contaminated cuttings, transport to shore for treatment, discharge to sea and reinjection show different environmental impacts. In the current paper, environmental aspects such as the CO2 and NOx emissions from all these three options will be presented in detail. The consequences of drilling with different rate of penetrations are outlined. The economical consequences of selecting one of these options will also be discussed.

The current analysis is based on a realistic example. The example is the development of a thought field in the North Sea area that can be drilled with a jack-up rig. The consequence of using a semi-submersible rig will be outlined. However, there will be no detailed calculation of those cases.
Real-time Fiber-optic Integrated System Used For Maximizing Coiled Tubing Wellbore Cleanouts in the Latin American Region
Authors: Webb Earl , Howard Robert , Garcia Alexis , Gleaves Jorge
Published: June 2014

Producing well conditions in the southern region of Mexico present challenges that can benefit from the use of a newly developed intervention technology. This paper describes the development of this real-time fiber-optic (RTFO) integrated system. RTFO is used for depth correlation and real-time pressure and temperature monitoring inside the coiled tubing (CT) and the outer annulus. Additionally, distributed temperature sensing (DTS) survey capabilities can provide instantaneous evaluation of downhole treatments in real-time. The data is transmitted by means of a 4-mm fiber-optic (FO) capillary to surface data acquisition equipment, allowing both monitoring and job execution changes in real-time. This technology allows operators to make immediate treatment decisions to help achieve the best results possible. Additional sensor expansion is possible because of the modular design of the bottomhole assembly (BHA).

This paper discusses the fast-track developmental process of the RTFO system as well as quantitative lab and full-scale yard testing. Case histories from three high-temperature deep candidate wells in the Latin American region are presented. Lessons learned from the initial field trials and the resulting next-generation design enhancements and sensor expansion capability of the tool are also highlighted.

The synergy of the CT RTFO system, cleaning nozzle selection, and a tailored fluid program proved to be a successful combination for effective cleaning of the case history wells discussed.
Measurement While Drilling, Logging While Drilling, and Rotary Steerable Systems Performance, Benefits, and Challenges in Managed Pressure Drilling and Underbalanced Drilling
Authors: Hussain Sajjad , Huelvan Yvon , Adams Waleed
Published: June 2014

Drilling engineers have been calculating hydrostatic pressure greater than reservoir pressure in almost all conventional drilling applications. This has resulted in various drilling challenges, such as reduced rate of penetration, differential sticking, mud losses, formation damage, wellbore stability, and formation fracture and associated cost. Managed pressure drilling (MPD) and underbalanced drilling (UBD) have played a vital role to significantly minimize these drilling problems onshore as well as offshore. Since most of the wells being drilled today include measurement-while-drilling (MWD), logging-while-drilling (LWD), and rotary steerable system (RSS) tools, the interface between these tools with MPD and UBD technologies has become extremely critical not only to understand but also to execute. These logging and steering tools have huge proven combined benefits in both MPD and UBD environments. The performance of all these tools in MPD and UBD environments is influenced by different challenges in terms of data transmission (mud pulse telemetry), hydraulics, steerability, and maintenance.
Smart Wells for Improved Water Management in the Presence of Geological Uncertainty
Authors: Valestrand Randi , Khrulenko Alexey , Hatzignatiou Dimitrios G.
Published: June 2014

This work investigates how smart well completions can be potentially used to delay breakthrough of injected fluids, and how to manage water/gas production while improving sweep efficiency and maximizing oil recovery factors at late stages of a fields life. The study objectives are to address, on a general and not field-specific basis, the following:

How should smart well completions be operated to effectively minimize water production and maximize economic gains? For which geological formations can smart well completions provide an added value compared to traditional ones?

A simulation model was built based on the Brugge static model, which consists of both fluvial and non-fluvial layers. Five deviated producers equipped with smart completions in different layers are used to control water production and study the impact of geological formations on the field's performance. The geological uncertainty is taken into account by using an ensemble of realizations of the reservoir properties. Both reactive and proactive control strategies are considered for the management of smart wells. The latter is achieved by optimizing oil production over a certain time period; several optimization procedures are examined and their influence on both wells and field fluids production is examined and evaluated. The results are validated for the whole ensemble to account for geological uncertainties, and a reliability study is performed to assess oil production losses that may result from a potential malfunction of smart completions. Based on the results obtained in this work, the following can be stated:

Smart wells provide the ability to effectively managing oil production while minimizing water production even when accounting for geological uncertainties; the economic gain is more significant for certain types of geological formations than others. Generally, proactive control strategies are more effective than reactive ones, if a sufficient time window is considered when conducting the proactive optimization. Depending on the reliability of the installed down-hole devices, potential malfunctions, which may occur during the smart wells life, could during the smart wells life could decrease their added value.
BlowFlow – Next Generation Software for Calculating Blowout Rates
Authors: Karlsen Hans Christian , Ford Eric P.
Published: June 2014

A blowout is known to be the most severe event that can happen during explortation of petroleum resources. Oil-spill preparedness is important in general, particularly in the arctic region where uncertainties about consequences are high and contingency planning for major accidents requires extra attention. Calculations of blowout rates and durations from potential blowouts is an important part of environmental risk management, both in the planning phase of a well and during otherwell activities.

BlowFlow is a software tool that has been developed for risk based evaluation of blowout scenarios in order to quantify blowout flow rates, volumes and durations. The results can be used as input to Environmental Risk Analysis, to dimension the emergency preparedness organization and identify both probability and consequence measures in the oil-spill preparedness planning. BlowFlow is meant as a cross-disciplinary tool for communication between petroleum, reservoir, drilling and HSE engineers. The basic design has been inspired by the guidelines given in [1]. Based on a fixed definition of potential blowout scenarios, BlowFlow provides probability distributions of potential blowout rates, durations and volumes for that can be used as input for the Environmental Risk Analysis. Since there are large uncertainties involved at the stage when such an analysis is performed, a stochastic modeling approach is used, i.e. Monte Carlo simulations and spline interpolations, based on multi-discipline expert input.
Real-time Measurement from Instrumented Wireline Mechanical Intervention Tools Reduces Risk and Improves Efficiency
Authors: Govil Amit , Guldahl Arne
Published: June 2014

Various well intervention techniques are used to enhance well productivity during the lifetime of a well. In general, perforation and stimulation retrievable bridge plugs are used for isolating zones during workover. Traditionally, retrievable plugs are recovered using wireline jars or powered mechanical shifting tools. During pulling or pushing operation, very limited information, such as surface cable tension, is available to the operator. In recent years, a new generation of wireline intervention tools has been introduced that enable real-time measurement and control of anchor force, anchor diameter, pull/push force, stroke length, stroke speed, and wellbore temperature and pressure.

This paper describes the application of real-time measurements in a recent operation in the Norwegian Sea.
Using Crosswell Data To Enhance History Matching
Authors: Ravanelli Fabio , Hoteit Ibrahim
Published: June 2014

One of the most challenging tasks in the oil industry is the production of reliable reservoir forecast models. Due to different sources of uncertainties in the numerical models and inputs, reservoir simulations are often only crude approximations of the reality. This problem is mitigated by conditioning the model with data through data assimilation, a process known in the oil industry as history matching. Several recent advances are being used to improve history matching reliability, notably the use of time-lapse data and advanced data assimilation techniques. One of the most promising data assimilation techniques employed in the industry is the ensemble Kalman filter (EnKF) because of its ability to deal with non-linear models at reasonable computational cost. In this paper we study the use of crosswell seismic data as an alternative to 4D seismic surveys in areas where it is not possible to re-shoot seismic. A synthetic reservoir model is used in a history matching study designed better estimate porosity and permeability distributions and improve the quality of the model to predict future field performance.

This study is divided in three parts: First, the use of production data only is evaluated (baseline for benchmark). Second, the benefits of using production and 4D seismic data are assessed. Finally, a new conceptual idea is proposed to obtain time-lapse information for history matching. The use of crosswell time-lapse seismic tomography to map velocities in the interwell region is demonstrated as a potential tool to ensure survey reproducibility and low acquisition cost when compared with full-scale surface surveys. Our numerical simulations show that the proposed method provides promising history matching results leading to similar estimation error reductions when compared with conventional history matched surface seismic data.
Hydrocarbon Flow Assurance: Low Rate and Pressure Gas Field Experience
Authors: Olayemi S. , Cano M. , Sanchez S. , O'Shea C. , Letendre F. , Solc P. , Verney M. , Maru M.
Published: June 2014

In the early life of most gas wells, there is sufficient reservoir pressure and flow rate to assure reliable evacuation of associated fluids from the reservoir/wellbore to the surface facility. In unconventional plays and in the case of Deep Basin gas field, this natural flow phase is usually short with a characteristic hyperbolic decline. When gas flow reaches critical velocity i.e. the minimum required velocity to lift out the liquids, pressure drop as a result of the hydrostatic head of liquid that is being left behind in the wellbore, increases till the well eventually stops flowing.

Reduced rates and ultimate recovery due to liquid loading has significant impact on the economics of tight gas developments. The methods (timer cycling, foam, plunger, velocity string) presented in this paper are relevant to many low rate and low pressure gas wells. These methods have been used singly or in combination to optimally utilize the reservoir's energy for long term flow assurance. Cost, rate and estimated ultimate recovery of the deliquification decision have been key driving factors in the pursuit of effective hydrocarbon flow.

Challenges and lessons learned thus far for deliquification decisions in Deep Basin are discussed, including the criteria/requirements for each method, inflow performance, wellbore hydraulics, water dynamics (formation and condensed water), scale deposition, associated secondary benefits/complications and field data showing impact.