bluuebunny/crossref_metadata_2025 huggingface dataset:
One-Spot Pilot Results in the Sabriyah-Mauddud Carbonate Formation in Kuwait Using a Novel Surfactant Formulation
Authors: Carlisle Charlie , Al-Maraghi Eissa , Al-Saad Bader , Britton Chris , Fortenberry Robert , Pope Gary
Published: June 2014

Kuwait Oil Company has recognized the implications of the recent technological advances that are very likely to transform the oil industry and make chemical enhanced oil recovery methods such as alkaline-surfactant-polymer (ASP) flooding a hallmark of enhanced oil recovery. An ambitious program to apply chemical EOR to both sandstone and carbonate oil reservoirs in Kuwait is already underway. In this paper, we present the first field results of this effort. First we discuss the approach used to design a novel surfactant formulation for a high-salinity, high-temperature, highly heterogeneous carbonate reservoir, the Sabriyah-Mauddud in Kuwait, and the evaluation of the ASP process in three one-spot ASP pilots (i.e., three two-stage single well chemical tracer tests). We summarize the results of the surfactant laboratory experiments used to select the final ASP formulation and we present detailed results and interpretation of the subsequent single-well chemical tracer test (SWCTTs) results using ASP chemicals as well as details of the field operation including quality control measurements performed in the field lab. The residual oil saturations measured before and after the injection of the ASP slug and polymer drives clearly show that the chemical solution was effective in mobilizing and displacing residual oil saturation following injection of water. The injectivity of high molecular weight polyacrylamide polymer was excellent despite the low permeability of the formation.
Monitoring Chemical EOR Processes
Authors: Mitchell Jonathan , Staniland John , Wilson Alex , Howe Andrew , Clarke Andrew , Fordham Edmund J. , Edwards John , Faber Rien , Bouwmeester Ron
Published: June 2014

A laboratory study on core plugs from a carbonate field confirmed the efficacy of an alkaline surfactant (AS) formulation at reservoir conditions. Continuous monitoring of remaining oil saturation (ROS) in short core plugs using spatially resolved nuclear magnetic resonance (NMR) can provide insights into the processes by which surfactants release post-water-flood remaining oil. In single short plugs, volumetric averages do not correctly quantify remaining oil due to capillary end effects (high remaining oil saturation post water flood observed at the outlet face of the plug), oil banks, and other flow heterogeneities. These effects are all quantifiable by NMR, allowing accurate monitoring of ROS. Here, consistent ROS values are obtained in the laboratory, in single-well pilots, and in single-well chemical-tracer (SWCT) tests. Laboratory core floods with nuclear magnetic resonance (NMR) monitoring at low magnetic fields therefore provide a valuable calibration of the NMR logs, in addition to the direct assessment of ROS. Corroboration across multiple length scales, spatial resolution, and correspondence with preferred logging measurements, all contribute to the value of NMR-monitored core-floods as a complement to field pilot studies.
West Salym ASP Pilot: Project Front-End Engineering
Authors: Karpan V. M. , Volokitin Y. I , Shuster M. Y. , Tigchelaar W. , Chmuzh I. V. , Koltsov I. N. , Tkachev I. V. , van Batenburg D. W. , Faber M. J. , Skripkin A.
Published: June 2014

Salym Petroleum Development N.V. (SPD) is a joint venture company of Shell and Gazprom Neft. SPD operates a group of oil fields located in Western Siberia (Russia) of which West Salym is the largest. The field is a mature waterflood with increasing water cuts and declining oil production. To counter the decline a tertiary oil recovery technique called Alkaline-Surfactant-Polymer (ASP) flooding was selected. According to our earlier studies the potential incremental oil recovery factor due to ASP injection may reach 15-20% of the ASP-targeted field STOIIP. Having identified significant target for the ASP flooding, SPD carried out laboratory program to establish a working ASP formulation. The formulation was tested under subsurface conditions in a single-well chemical tracer field trial. The trial has demonstrated significant reduction of oil saturation in the flooded zone due to the ASP injection. An investment decision for the next development stage of the West Salym ASP project, a multi-well injection - production pilot, was taken in Q4 2012. In 2014 SPD plans to construct the surface facilities and ASP injection is expected in 2015.

The paper focuses on the current status of the ASP pilot project. The objectives of the pilot are to demonstrate the oil recovery potential of ASP technology and collect enough information for decisions on the subsequent commercial stage. The pilot surveillance program, the surface facilities and the subsurface configurations were specifically designed to meet these objectives.

In this paper our recent progress on optimization of chemical formulation is also discussed to demonstrate how the properties of chemical ingredients of an ASP flood are influencing the design of the surface facilities. Different design options for the key elements of the surface facilities were evaluated emphasizing the role of process requirements determined by properties of the chemicals used, as well as logistics and the harsh weather conditions.

West Salym reservoir rock and fluid properties are typical for West Siberian oil fields. Hence, success of this ASP pilot project could pave the way for subsequent ASP projects in other West Siberian oil fields and have significant impact on the Russian oil industry.
Lessons Learned from Applying Particle Gels in Mature Oilfields
Authors: Qiu Yue , Wu Fengxiang , Wei Mingzhen , Kang Wanli , Li Baohong
Published: June 2014

As an effective conformance control method, gel treatments have been applied widely in mature oilfields to reduce excess water production by preferentially plugging the water thief zones after long-term water flooding. Performed particle gels (PPGs) are becoming more and more popular in China for this purpose because they overcome some of the inherent drawbacks of in-situ gel systems, including the lack of control over the gelation time, gelling uncertainty due to shear degradation, chromatographic fractionation or change of gelant composition, and dilution by formation water. However, the literature in this area remains limited, providing few case studies or data analyses regarding the use of PPG in oilfields.

This paper reports field applications of particle gels in water flooding, polymer flooding and ASP flooding. In Chinese oilfields from 2001 to 2012, we treated 655 wells with 12,765.62 tons of particles; the injected dry particles typically weighed between 11.5 to 20.6 tons per well. The applications covered both sandstone reservoirs and naturally fractured reservoirs with different temperatures and formation salinities. Properties of the particles applied in oilfields, such as the particle size, swelling ratio, and thermal stability, were tested. Eight cases are reported in this paper as examples of how to design and evaluate gel treatment projects. The results showed that the oil production rate increased from 14.3% to 50% and that water production decreased to the range of 0.4% to 4.7% after treatment.

Based on the case study, highlights of illustrative PPG field applications and results are presented. Criteria for well selection and PPG treatment design are provided to serve as a guide for the kinds of conditions under which PPG conformance control can be applied successfully.
Microemulsion Phase Behavior Measurements Using Live Oils at High Temperature and Pressure
Authors: Jang Sung Hyun , Liyanage Pathma Jith , Lu Jun , Kim Do Hoon , Pinnawala Arachchilage Gayani W.P. , Britton Chris , Weerasooriya Upali , Pope Gary A.
Published: June 2014

Microemulsion phase behavior is the most important phenomenon related to any type of chemical EOR using surfactants. Although the impact of solution gas and pressure on microemulsion phase behavior has been studied for decades, only a very limited amount of data are available in the literature and this is especially true at high temperature and pressure, nor is there a good theory available to guide our understanding of this behavior. A very large number of new chemical EOR projects are underway and almost all of them now involve live oil whereas in the past most of the projects did not involve live oil. The availability of sapphire view cells rated to 150 °C and 5000 psi has greatly extended our laboratory capability to do live oil studies under conditions where almost no data exist. These view cells allow us to make visual observations very similar to the critical phase behavior observations that we routinely make using glass pipettes at low pressure. For example, the classical emulsion test can be performed to qualitatively estimate the interfacial tension and viscosity. Also, it is easy to observe phase separation of the microemulsion/water/oil mixtures, the oil and water solubilization ratios and the equilibration times. This can be done using multiple cells so that salinity or other key parameters can be varied to determine optimum salinity and other key design parameters. This has allowed us to perform more tests at higher temperature and pressure with higher solution gas ratios than previous tests. The results are highly significant with very important implications for field applications to live oil reservoirs. Specifically, we have found the optimum salinity is closer to the dead oil than expected and higher than the value for surrogate oils made based on the equivalent alkane carbon number approach. The development of formulations that meets the aqueous stability criterion at optimum salinity is therefore more challenging than previously realized.
Dynamic Interfacial Tensions and Contact Angles of Surfactant-in-Brine/Oil/Shale Systems: Implications to Enhanced Oil Recovery in Shale Oil Reservoirs
Authors: Mirchi Vahideh , Saraji Soheil , Goual Lamia , Piri Mohammad
Published: June 2014

Unconventional shale oil resources have emerged as a significant source of fossil fuels in recent years. The oil contained in shales is held in natural microfractures, micropores, and inside nanopores of the organic matter. The strong capillary forces in these pores can bind the oil to the surface with strengths that are inversely proportional to the pore radius. In order to recover more oil from these pores, it is beneficial to reduce the capillary pressure by manipulating the interfacial tension and contact angle of oil/brine/shale systems using surfactant solutions. The main consideration in surfactant flooding is to optimize brine salinity and surfactant concentration while minimizing their adsorption on rock surfaces. Although the effect of some surfactants on recovery in shale oil reservoirs has been studied in the past, the mechanism is still unclear. Moreover, the limited data available in the literature is not representative of the actual reservoir conditions.

The objective of this study is to elucidate the oil displacement mechanisms in shale oil by surfactant flooding. The phase behavior of several anionic surfactants was studied in the presence of crude oil at reservoir temperature (i.e. 80 °C). The results of these tests were used to screen the best surfactants. Dynamic interfacial tensions (IFT) and contact angles (CA) of selected surfactant-in-brine/oil/shale systems were measured by the rising/captive bubble technique using a state-of-the-art IFT/CA apparatus. The apparatus was thoroughly validated with various systems using the axisymmetric drop shape analysis technique. Using the same methodology, the effects of surfactant concentration (0.01 to 0.1 wt%) and brine salinity (0.1 to 5 M NaCl) on IFT and CA at ambient and reservoir conditions (i.e. 80 °C and 3000 psig) were studied. Surfactant adsorption on shale samples was also measured in brines at ambient conditions. Our data reveal that the most effective surfactant was able to reduce the oil-brine IFT from its original value (23 mN/m) down to 0.3 mN/m at reservoir condition. A reduction in the IFT value and an increase in the dynamic contact angle of oil drop on polished shale surface were observed with the addition of surfactant and salt to the system. A trend between these parameters, pressure, and temperature was also reported.
Drilling Depleted Reservoirs using Controlled Mud Level Technology in Mature Subsea Fields
Authors: Fossli Børre , Stave Roger
Published: June 2014

Many subsea fields on the NCS are now entering maturity. As reservoir pressure declines, this inherently introduces significant well construction and well delivery challenges. Wells are the biggest driver for increased recovery. Depletion and increased formation pressure heterogeneity in mature fields are driving costs and slowing well delivery. For fields developed with fixed platforms, conventional pressurized Managed Pressure Drilling (MPD) techniques developed on land has been used for some time to combat these challenges. For floaters with subsea Blow Out Preventers (BOPs) and Low pressure marine drilling risers in harsh environment, other technologies are needed. EC-Drill is a new technology developed by AGR Enhanced Drilling specifically for floaters which will regulate the drilling fluid level in the marine riser in order to manage the wellbore pressures. A subsea mud pump is connected to the marine drilling riser and is used to manage the fluid level within the riser up or down. The drilling fluid is pumped back to surface from a lower level on the riser so that the hydrostatic pressure in the wellbore can be managed more effectively. This also enables using conventional mud weight to drill depleted reservoirs. The technique also allows for precise control of wellbore pressures and enables drilling with close to constant bottom hole pressure. The technology will ensure improved hydraulics which can result in; improved hole cleaning, higher rate of penetration, improved casing/liner cementing, less downtime (NPT) due to formation pressures heterogeneity and longer horizontal sections may now be drilled in depleted reservoirs, etc.

This paper discusses the challenges related to drilling in depleted reservoirs and outline the new drilling technique that is available to solve these and other drilling challenges on the Norwegian Continental Shelf (NCS).
High Quality Flow Information from Tracer Data
Authors: Huseby Olaf , Hartvig Sven K. , Jevanord Kjersti , Viig Sissel O. , Dugstad Øyvind
Published: June 2014

This paper describes a systematic methodology to extract as much information as possible from inter-well tracer tests. Interwell tracer testing has been used extensively in Norway and world-wide the last 2-3 decades and is proven as an efficient technology to map well-to-well communication and sweep, and to evaluate the effect of water and gas injection projects.

Significant information can usually be extracted from tracer curves, in addition to the immediate injector-producer communication available upon first tracer breakthrough. Improved tools and methods, such as residence time distribution (RTD) analysis, can quantify how effective water and gas floods displaces water, and reveal flow paths and channels prior to infill-drilling, polymer blocking etc.

However, prior to interpretation of tracer data, it is essential to remove uncertainties due to water or gas re-injection, commonly applied to reduce discharge to the environment and save scarce water-resources. However, recirculation of produced water and gas can be seriously misleading when tracer data are interpreted, because tracers will be re-injected with re-injected water or gas.

In this paper we show how the background tracer concentration due to re-injection can be removed in a systematic and unambiguous manner. The methodology is tested on data from tracer campaigns in two field cases. The tracer data from the field cases are subsequently used to evaluate water flooding sweep and reservoir heterogeneity using residence time distribution (RTD) analysis. The field case results show that the method is well suited to obtain quantitative flow pattern information from tracer data, and provides an effective tool for reservoir engineers that use tracer data to extract information about reservoirs.
Collecting Large Sample Volumes While Drilling With Minimal Contamination
Authors: Cartellieri Ansgar , Tran Pei-Chea , Galvan-Sanchez Francisco
Published: June 2014

Acquiring samples earlier in a well plan minimizes reservoir uncertainty and enables better planning for future activities. The deployment of a logging while drilling (LWD) fluid analysis and sampling tool in this scenario enables the operator to mitigate the risk of data acquisition and improves access to challenging boreholes including deviated wells and extended reach drilling.

This paper discusses the deployment of a LWD formation pressure testing and sampling tool in a high angle well in Asia Pacific. The objective was to collect representative gas samples for geochemical analysis and proper facilities design. Therefore large representative sample volumes of up to twenty liters were required to ensure a proper lab analysis of the reservoir fluid properties. These samples were taken in two different wells during dedicated sampling while drilling runs.

The highest priority was maintaining the chemical composition of the sample as close to in-situ condition as possible. Consequently, a minimized chemical adsorption within the tool's metallurgy was required. Although the metallurgy of the tool and the tank systems are inert to adsorption of most geochemicals in reservoir fluids, it was decided to apply a coating to some of the tanks.

The contamination level during the clean-up process while sampling gas is difficult to predict because an emulsion may be generated that masks the clean-up response and gas signature of the sensors during fluid analysis. One of the recent improvements to the LWD fluid analysis and sampling service is real time mobility and compressibility measurement. These two measurements are solely based on the pump system and not adversely affected by immiscible fluids. It will be discussed how the clean-up process can be improved furthermore without adding tool functionality and increasing the service complexity.
The Effect of Peroxide Concentration when Removing Iron from Brine: A Kinetic Study
Authors: Patil Anil , Managave Pallavi
Published: June 2014

High-density completion brines are widely used in well completion and workover operations. However, these high-density brines are susceptible to iron contamination and thus must be treated for iron removal. In particular, high-density brines containing zinc are the most difficult to treat for iron removal due to their relatively low pH.

Multiple approaches and technologies have been used for brine reclamation, including the use of an oxidizing agent such as peroxide. Unfortunately, conventional reclamation processes using peroxide usually require multiple steps, significant chemical additions, long reaction times, and extensive filtration to remove the iron and the excess treatment chemicals. However, it has been observed that using a higher concentration of peroxide can quickly and effectively remove iron even from brines containing zinc.

This paper describes the effectiveness of various peroxide concentrations used to remove iron from zinc bromide and calcium bromide brines. In a laboratory experiment three concentrations of hydrogen peroxide (0.6%, 1.5%, and 3%) were tested for their ability to remove iron from these two brines over various time intervals. The 0.6% peroxide reduced the iron concentration in the zinc bromide brine by 24% in 48 hours. Increasing the hydrogen peroxide concentration from 0.6% to 1.5% resulted in a 98% reduction of iron in 48 hours. However, maximum effectiveness was achieved with a 3% hydrogen peroxide concentration, which reduced the iron by 100% in just 6 hours. Experiments performed on calcium bromide brine showed similar results.

A kinetic study shows that the reactions follow first order kinetics. From the standpoint of kinetics, we calculated the initial rate of reaction for each concentration of peroxide which proved that the reaction rate increased as the peroxide concentration increased. For the 0.6% hydrogen peroxide concentration, the calculated rate constant was 3x10-6S-1 with the half-life of 64.16 hr. For the 3% hydrogen peroxide concentration, the rate constant was calculated as 2x10-5 S-1 and with a half-life of 5.2 hrs. In addition, we calculated the activation energy for each of the reactions which are detailed in the paper.
Electric Line Riserless Light Well Intervention (RLWI) Methods Key to Increasing Recovery from Subsea Wells
Authors: Karlsen Ole Eddie , Andrews Garry
Published: June 2014

The number of subsea wells has increased steadily and by the end of 2012 exceeded 5,500 (Infield 2013). These wells pose a number of challenges including generally lower recovery factors compared to wells with surface access. The high operating rates of rigs have had a natural damper on the incentive to increase recovery rates, as the balance between cost and revenue has been unfavorable—even with increasing oil and gas prices. However, this has also spurred the drive to develop alternative methods to enhance recovery and cope with the challenges of maturing fields and exploration under more difficult circumstances.

Adopting frequent lightweight well intervention has proven crucial for subsea operators to realize the potential of 50% oil recovery. Such operations are becoming more common, but there are increasing challenges and demands as development moves toward deeper waters. To reduce overall risks and use the natural resources more effectively, new technology and improved operational efficiency are required. The ability to carry out frequent, scheduled interventions as opposed to remedial interventions is fundamental to raising recovery rates.

Lightweight and riserless well intervention has proven its potential for driving improvement in recovery rates. The ability to substitute rigs with smaller, dynamically positioned light well intervention vessels has a major impact on cost and scheduling. Electric line (e-line) Riserless Light Well Intervention (RLWI) has demonstrated its value and the fact that it is an inherently safer method for intervening on subsea wells compared to conventional, heavier methods using a riser.

This paper gives a detailed account of the opportunities to improve recovery rates in subsea wells by having access enabled with this lighter, more efficient, and ultimately more productive intervention method. Several case histories and examples will be shown.
World's First Hydrate Plug Milling on E-Line
Authors: Karlsen Ole Eddie , Skeie Terje , Buch Jorgen , Keith John
Published: June 2014

Operators often struggle with a complex phenomenon causing unwanted and often unpredicted hydrate plugs to form in producing or injection wells, blocking production and re-entry to the well. Conventional remediation methods can be costly, time consuming, and are often ineffective.

This paper will share the knowledge gained from a world's first operation, demonstrating that hydrates can be milled using electric line (e-line) tools. The operation was performed from a Vessel Fit for Purpose (VFFP) as a Riserless Light Well Intervention (RLWI) operation in the North Sea, offshore UK.

A hydrate plug was tagged below the subsea tree in a water injection well. This unconventional solution was chosen to restore injectivity to wellbore and minimize non-productive time (NPT). Unfortunately, during the operation, harsh weather caused operations to be stopped due to safety issues, and prevented removal of the entire hydrate plug. At that point, reestablishing functionality to the downhole safety valve became a major issue. Fortunately, in less than 20 hours of milling time 173 ft (52 m) of hydrates were removed on e-line and the operator was able to re-establish the functionality of the downhole safety valve.

E-line technology provided a swift and accurate resolution to the problem, proving that hydrates can be dealt with as easily as doing any other e-line intervention and that the technology can be run in a ‘live’ well under pressure.
Integration of Real-Time LWD Spectroscopy Data to Optimize Drilling through Paleosols Supports Low Energy Drilling Operations
Authors: Cook Michael , Horstmann Mathias , Irondelle Matthieu , Hugall Jeremy
Published: June 2014

Paleosols are fossil soils, and provide additional challenges to drilling and completion operations as they are generally weaker and more friable than rocks such as shale or sandstone. This weakness often results in borehole degradation, wash- or breakouts and even formation collapse, which poses challenges to well operations. It is therefore important to identify paleosol horizons whilst drilling and perform operations in a manner that will minimize damage to these formations. Conventional log data is in many cases unable to uniquely identify paleosols.

Recent analysis of real-time GR capture spectroscopy, which is available in logging-while-drilling, has assisted in identifying these horizons and aided the successful drilling and completion of several wells on the Gullfaks Satellite fields. Previous work demonstrated that paleosols could be characterized using iron content. Spectroscopy data was used to determine the concentration of a suite of elements whilst drilling. By combining conventional log data with measurements of iron content it has been possible to identify weaker paleosol horizons based on an increased iron content, high Gamma Ray signature, and high bulk densities. This data has been utilized in real-time to avoid excessive work of the drillstring over the paleosol zones, particularly with respect to stabilisers and the bit, and to optimize the position of the bottom hole assembly (BHA) during formation pressure testing.

In order to reduce formation damage whilst drilling, a Low Energy Drilling Operations (LEDO) strategy in which the drilling parameters are only changed one at a time in order to establish trends, off bottom circulation is minimized and ROP is limited has been used. This technique was combined with traditional LWD triple combo data along with GR spectroscopy, measured matrix properties and borehole images. This approach has made it possible to successfully drill several wells through paleosol- rich formations.
Advances in Real-Time Data Monitoring for Pressure Pumping
Authors: Svensson I. , Sach M. , MacLeod A.
Published: June 2014

In the 2000s the focus for real-time data transfer, monitoring and visualization has been in the drilling domain. The WITSML open exchange standard has been a key factor to this success. Compared to the legacy WITS standard, WITSML has advantages in interoperability, the ability to load historical data and the capability to get updated data, e.g., for post-acquisition quality control and assurance.

Recently, Baker Hughes has completed several developments related to the transfer of real-time data from pressure pumping services based on WITSML. One typical case history is real-time monitoring of wellbore intervention performed with coiled tubing in Norway, and another important application is fracturing operations in the US. We will also show examples of integrated coiled tubing drilling operations in Norway and acidizing and gravel pack jobs done in Brazil.

Baker Hughes is now also supporting the new WITSML stimJob object. Fracturing operations can create large volumes of data, and the stimJob object creates a valuable and timely post-job treatment report. The data in the report can be integrated with other data, like production data, for production optimization. We will show examples of successful transfer of stimJob data to Geological and Geophysical support applications.
Even a Small Change in Procedures can Give Unexpected and Unwanted Results: A Troll Experience
Authors: Carlsen Truls , Hanøy Kim Richard
Published: June 2014

Severe losses when RIH with 10 ¾ x 9 ⅝" MLT liner in the reservoir on the Troll field was observed in three successive wells. A detailed study to find the cause was undertaken. The only deviation from previous liner runs was a new circulation procedure at 12 ¼ section TD. After re-establing the best practice procedures no further loss incidents have been observed. This paper confirms the need for multi-disciplinary discussions before the drilling procedures are changed.
An Investigation of Different Approaches for Probabilistic Cost and Time Estimation of Rigless P&A in Subsea Multi-Well Campaign
Authors: Moeinikia Fatemeh , Fjelde Kjell Kåre , Saasen Arild , Vrålstad Torbjørn
Published: June 2014

High demand for plug and abandonment (P&A) of subsea wells in the forthcoming years on Norwegian Continental Shelf, low availability and high daily rate of semisubmersible rigs as well as high proportion of P&A cost to total cost of drilling exploration wells challenge industry and intensify looking for alternatives and rigless technologies which can make P&A operation more cost effective and release time of semisubmersible rig earlier. Light well intervention vessels currently can take over some parts of P&A operation and release time of semisubmersible rigs in order to function in drilling and completing of new wells. In addition these vessels have a low daily rate compared to semisubmersible rigs and decrease cost associated with P&A. A systematic yet simple approach is required to acquire a correct picture for expenditure and time of these alternative technologies.

In this paper, potentials and experiences of light well intervention vessels for P&A and benefits associated with them will be discussed. An example case is considered wherein a new technology is deployed from a light well intervention vessel to set surface plugs in a multi-well campaign. Thereafter, benefits associated with application of this rigless technology are discussed and highlighted.

The paper will discuss different approaches for structuring probabilistic time and cost estimation of multi-well P&A campaigns discussing at which level these should be performed and what is the most appropriate approach with respect to modularity and efficiency. This will also be seen in relation to the Oil and Gas UK cost estimation guideline for P&A and the NORSOK technical specification. The objective is to keep the simulations simple while still acquiring the correct range of time and cost for multi-well P&A operation in order to make the proposed approach applicable for the industry.
Development of a Smart Flow Diverter
Authors: Spreckelmeyer Niko , Regener Thorsten , Schwartze Sascha , Clemmensen Carl C. , Eidem Morten , Grindhaug Gaute
Published: June 2014

In liner drilling operations the annular velocity of the drilling fluid drops significantly when it transits from the narrow cross section of the openhole-liner annulus into the increased annular volume between the casing and the drillpipe above the liner. The reduced annular velocity might cause critical hole-cleaning problems that can jeopardize the entire drilling operation and therefore needs to be managed.

To effectively mitigate this problem Statoil (operator) and Baker Hughes (service company) have jointly developed and tested a smart flow diverter (FLD) that can be positioned in the drillstring directly above the liner running tool.

The FLD is designed as a standalone tool that can be placed anywhere in the drillstring and can be used in different applications where enhanced hole cleaning is required, independently of the measurement-while-drilling (MWD) supplier. The tool ultimately must deliver a continuous flow split during the drilling operation, so the main considerations of required features and specifications were carefully reviewed in the early phase of the project:

Unlimited activation/de-activation on demand Failsafe closed No compromising of and interference with normal well-control procedures Direction of flow exit to annulus Adjustable flow split No interference with mud pulse telemetry

The tool is activated either by drillstring rotation and a differential pressure threshold or by a flow pattern signal if string rotation is not possible. Both activations can be incorporated in standard connection procedures, thereby eliminating non-productive time (NPT). This paper highlights and discusses the background for the development, specifications, features and method of activation.
Drilling Technology Taking Drilling Operations to New Frontiers
Authors: Yadav Anurag , Al-Tajar Tammam , Ali Anis
Published: June 2014

Drilling performance on horizontal wells typically drilled in re-entry / workover operation is key for the project to become economically feasible to produce hydrocarbon. Due to presence of a non-linear pressure gradient, a re-entry well-construction design required a casing before entering reservoir and drilling further in a slim-hole. A slim-hole ie 3 7/8″ hole, was not meeting well objectives from logging and completion perspective. Hence, a 5 ½″ x 7″ expandable liner was required to be set in order to drill a 5 ½″ production hole. To accommodate a 5 ½″x 7″ expandable liner, a 6 1/8″ pilot-hole was required to be drilled and enlarged up to 7″; this was historically achieved by a dedicated hole opening trip after drilling a conventional 6 1/8″ because the section was drilling through extremely challenging hard anhydrite layers which were not only hostile towards directional work but were also generating malign drilling environment through severe shocks & vibrations and poor penetration rates (causing lot of tool failures and damages). Since the well design called for high dogleg severity well profiles, motor assemblies were used to drill the well because conventional rotary steerable systems (RSS) were unable to deliver the required directional performance due to unfavorable directional response of the formations. In this operation, an integrated engineering approach was developed to design a drilling system that can simultaneously drill and enlarge hole that lead to successful delivery of a high dog-leg severity well profile without causing any tool failures or mechanical damages. This operation was a first such example in the industry where this drilling system was utilized. The success of the operation relied on selection criterions used for adopting technologies in the BHA and was based on the design process followed to conduct advanced engineering studies. The engineering approach taken in this successful operation highlighted how an innovative application of a truly hybrid high build rate RSS tool had expanded an existing drilling envelope to new frontiers.
Back-Pressure MPD in Extended-Reach Wells - Limiting Factors for the Ability to Achieve Accurate Pressure Control
Authors: Gravdal Jan Einar , Siahaan Hardy , Bjørkevoll Knut S.
Published: June 2014

Extended-Reach Drilling (ERD) with narrow pressure margin or uncertain geo-pressure is a challenge with respect to accurate pressure control. The back-pressure Managed Pressure Drilling (MPD) method has been widely used in drilling operations with the aim of controlling annulus pressure within safe bounds, and may also be applicable for ERD wells. However, the ability to control the pressure accurately is limited by several factors. Some of which are related to back-pressure MPD operations in general and some of which are more specific to ERD wells. In this paper a study is presented on how pressure control is affected and sometimes limited by the actual data availability and quality, equipment, hydraulic models, control algorithms, and downhole conditions during an MPD operation in an ERD well. By using a transient well flow model, the theoretically obtainable MPD performance can be simulated. In particular, the benefit by utilizing real-time downhole pressure measurements transmitted by a wired drill pipe is demonstrated by simulations. It is shown quantitatively how variations in sensor delay and bandwidth will influence the ability to control downhole pressure accurately in an ERD well.

Benefit by this approach is a more accurate prediction of what is obtainable with MPD and how various factors may influence the ability to control downhole pressure.
Wellbore Investigation and Perforation of a Highly Deviated Well Using a Wireline Tractor and Strip Guns Offshore Angola
Authors: Guerra Enrique , Guillory Ryan , Bhattacharyya Biswajit
Published: June 2014

Since the early decades, through-tubing wireline (WL) interventions have been a necessary routine of the oil and gas industry. The practice of well intervention has benefited from the evolution of WL tools on its imposed quest to keep up with the trend of increasing complexity in wellbore and completion development.

Deployment of WL tools through tubing, from early and simple devices (e.g., gauge cutters, lead impression blocks, tubing plugs) to state-of-the-art logging and well intervention prototypes, experienced a significant leap forward with the application of electric line (e-line) tractors in the mid-1990s. Since then, many oil companies have implemented the use of tractors to make a great variety of rigless well interventions feasible, both technically and economically.

Over these lines, WL perforating of long, highly deviated wells through tubing, especially those with relevant ID restrictions, indubitably requires challenging, ingenious, and risked-assessed selection of the most convenient perforating and deployment systems. Working in remote locations, where availability of specialized tools and qualified personnel on short notice are often limited, adds an extra burden to the everyday complexity of operations.

This paper describes the unconventional, but successful, use of a WL tractor to (1) investigate a tubing-conveyed perforating (TCP) completion failure and (2) save the highly deviated "S-shaped" well from a costly offshore rig workover by perforating with a strip gun deployed more than 14,000 ft from surface. The well is located in Angola at a water depth of 1,206 ft.
When BlackOil Approximates Compositional Simulation on Dry Gas Injection - A Case Study in Oseberg Vestflanken Field, Norway
Authors: Xiao-Qian Lin , Meisingset Knut Kristian , Nybø Roger , Espelid Øystein
Published: June 2014

Dry gas injection has been widely practiced across the oil and gas industry. Under this approach, lean gas is injected into the producing formation to attain amongst many others the three key physical responses: (1) Reduction in reservoir pressure depletion (2) Re-vaporization of in-situ condensate dropout (3) Swelling of reservoir oil. All of these reactions could yield to improved hydrocarbon recovery. However, not all of the responses are fully described by standard blackoil simulation. In such instances, compositional modeling is required to provide for accurate estimate of field recovery but at the cost of time and human resources.

Through a field case study on the Vestflanken reservoirs, this paper will reveal the strategy used to evaluate and justify the necessity of compositional modeling in a dry gas injection project. Blackoil and compositional models were constructed with the use of Eclipse 100/300 and the results were compared.

The study has concluded that (1) Pressure depletion was equally well described in blackoil and compositional simulations (2) In the event of short injection time during which the injected gas stream was unproduced, re-vaporization of dropout condensate would not be a dominant recovery process. Blackoil simulation approximates the results of compositional model (3) In saturated reservoir conditions, oil swelling is insignificant.

In addition, the study has also recommended on a workflow that enable the engineers to estimate the maximum impact of condensate re-vaporization on field recovery in the absence of compositional model. By the use of vapor incremental rate function in blackoil simulator, the uncertainty range in re-vaporization rate, which also equates to the key discrepancy between blackoil and compositional simulations on re-vaporization behavior could be quickly established. The magnitude of discrepancy serves to justify the necessity of compositional modeling work thereafter.

An accurate reservoir simulation is important for large investment like dry gas injection. General impression amongst engineers were such that compositional modeling is imminent but this paper has demonstrated a case scenario in which blackoil provides just as good a representation of the fluid behavior as the compositional simulation. It serves as a good analogue and reference for all reservoirs and projects of similar nature.
Tail-In Proppant and its Importance in Channel Fracturing Technique
Authors: Barasia A. , Pankaj P.
Published: June 2014

The channel fracturing technique achieves heterogeneous proppant placement by pumping pulses of proppant laden slurry and clean fluid in alternating sequence. Successful creation of proppant banks in the fracture provides stable channels of infinite conductivity which reduces pressure drop across the hydraulic fracture and enhances production. To date, more than 15,000 fracturing jobs have been successfully placed in various types of formation and completions using the heterogeneous proppant placement technique.

The mechanics of delivering the treatment involves pumping pulses of alternating clean and dirty pulses of fluid with fibers that keeps the proppant in suspension. This is then followed by a continuous proppant "tail-in" stage towards the end of the job before the flush stage. This tail-in ensures continuous proppant bank at the near wellbore region to ascertain good connectivity between wellbore and the channel spaces created during the treatment.

To understand importance and requirement of tail-in, simulations and field execution of jobs with or without tail-in in channel fracturing treatment have been done. Furthermore, a bigger sized unconventional rod-shaped proppants have been also used towards end of the channel fracturing treatments. The unconventional proppants not only helped on such treatments to minimize pressure drop across the tail-in but also helped to reduce proppant flowback in softer formations.

The impact of tail-in on pressure drop and production rates in different formations have been consolidated in this study which provides proppant selection criteria for channel fracturing tail-in stage. Simulation results in shale and sandstone reservoirs and the field treatment case histories comparing the production results for wells completed with and without tail-in in channel fracturing treatment are presented.
Potential Utilization of Geopolymers in Plug and Abandonment Operations
Authors: Khalifeh Mahmoud , Saasen Arild , Vrålstad Torbjørn
Published: June 2014

When a well reaches the end of its life-cycle, it should be permanently plugged and abandoned. Geopolymers have recently attracted attention as potential alternative materials to cement, and hence, have the potential to be used as permanent barriers. This paper presents a brief overview of geopolymers and their chemo-physical properties and how they can be applied to the plug and abandonment (P&A) operation.

To give a better understanding of geopolymers, Class C fly ash-based geopolymers were prepared and examined. Fly ashbased geopolymers were produced by the alkali –activation of the Class C fly ash with an activator solution (a mixture of NaOH and sodium silicate solution). The NaOH solution was prepared at three concentrations of 6, 8 and 10 mol/L and it was mixed with the sodium silicate solution at a mass ratio of 1 in order to prepare the activator solution. The fly ash-C to liquid mass ratio was 1.9, typically producing final densities in the range of 2.44 s.g. In order to investigate the effect of curing temperature on the mechanical property of the obtained geopolymer, specimens were cured at two different temperatures (87 °C and 125 °C) under a pressure of 5000 psi. This work studies the effect of curing temperature and NaOH concentration on the mechanical properties of the specimens. Uniaxial compressive strength (UCS) tests and Ultrasonic cement analyzer (UCA) tests were carried out to measure the compressive strength development of the specimens. Scanning Electron Microscope (SEM) images were taken to study the microstructure of the specimens. Measurements of pH of ground specimens was performed and based on the obtained results pH alters during the curing time. These measurements will found a basis for selecting the correct material for the P&A operation.
A New Benchmark in HPHT Operations: Safe and Successful Well Testing On the Jackdaw Gas Condensate Field in the North Sea, UK
Authors: Shumakov Y. , Williams A. , Hetherington G. , Davidson B. , Whittle T. M.
Published: June 2014

Well Testing for reservoir characterisation and production assessment has always been critical, especially in offshore high-pressure, high-temperature (HPHT) environments. A limitation of technology available for HPHT environments in conjunction with strict safety and environmental constraints elevate the operational challenges over those associated with non-HPHT well testing.

The use of a conventional test separator from well opening in gas-condensate well testing is not straight forward, especially in high pressure wells, due to slugging and rapid and continuous phase changes in the early life of the test. Concurrently, accurate flow rate measurement from well opening is crucial for well test interpretation, and estimation of total recovered well effluent. Well test interpretation of fast reservoir pressure response typically observed in HPHT conditions becomes complex, and thus the pressure change needs to be accurately measured at a high scanning rate by downhole memory gauges. Furthermore, and throughout the duration of the well test, personnel safety and environmental responsibility are paramount, thus emphasizing the importance of up-front planning and application of advanced technology, qualified to maximum anticipated conditions, to eliminate and mitigate the associated risks of HPHT well testing.

This paper describes the unique combination of technology, selection, and qualification process of downhole equipment for long duration and anticipated operation conditions that enabled successful well testing on the high profile HPHT Jackdaw gas - condensate field situated in Block 30/2 & 3, the North Sea. The paper also describes the benefits of using a new generation of well test separator, which is equipped with coriolis meters and an adjustable weir plate for optimum separation efficiency in HPHT environments. It also demonstrates how real-time collaboration of experts at multiple sites via a real-time data delivery system was crucial in acquiring high quality data and providing concurrent feedback to ensure safe and trouble-free well testing operations.