bluuebunny/crossref_metadata_2025 huggingface dataset:
Bottomhole Pressure Prediction Using Multiphase Hydraulics in Underbalanced and Managed Pressure Drilling Operations
Authors: Morales Gabriela , Urdaneta Gustavo , Poletzky Isabel C.
Published: September 2016

Underbalanced drilling (UBD) and managed pressure drilling (MPD) techniques provide the capability to precisely control bottomhole pressure (BHP). During upfront planning and engineering, as well as during the actual operation, the calculation of the BHP using a wellbore hydraulics simulator is crucial because it helps to determine the operational drilling parameters necessary to achieve the desired objectives, equipment requirements, and operational limits.

Several wellbore hydraulics simulators and multiphase flow pressure gradient methods are available in the industry to facilitate the calculation of the BHP, especially when using gasified fluids in both MPD and UBD, and when accounting for formation influx when drilling underbalanced. Furthermore, before beginning operations, the wellbore hydraulics model is calibrated using the actual readings from the pressure while drilling (PWD) sensor. Simulations were performed for several well designs to compare results and to evaluate the possible underlying causes of the differences among simulators and correlations.

Although the primary components in the BHP calculation include density, frictional pressure losses, and applied surface back pressure (SBP), another component that is usually overlooked during planning and engineering is the surface pressure losses because a considerably larger surface pipe line diameter is typically used for UBD. A case study illustrates the effect on the target BHP for an underbalanced operation when using a smaller pipe diameter. Field data are also used to illustrate the calculation of surface pressure losses; a comparison of the calculated and measured values is also evaluated for different scenarios.

This paper focuses on a comparative study of the various methods and correlations available in some wellbore hydraulics simulators and evaluates the results for different wellbore scenarios using MPD and UBD. The study evaluates actual field measurements, including PWD, surface pressures, flow rates, and standpipe, for some of the scenarios. Conclusions and recommendations address the gaps and areas of improvement that should be considered for future developments.
Evolve: A Linear Workflow for Quantifying Reservoir Uncertainty
Authors: Thiele Marco R. , Batycky Rod P.
Published: September 2016

The EVOLVE workflow addresses a longstanding and difficult problem in reservoir modeling: quantifying the uncertainty in NPV forecasts ensuing from uncertainties related to geological and simulation parameters, forecast scenarios, and economic variables.

The EVOLVE workflow is linear in nature composed of four key stages: (1) screening and selection of geological models; (2) calibration to field-scale measured data; (3) local calibration using well-level measured data; and (4) applying differing forecast scenarios on the resulting ensemble of models. NPV calculations are an extension of stage (4) as forecast responses are translated into NPV numbers using economic parameters such oil price, operating expenses (OPEX), and capital expenses (CAPEX).

The novelty of the EVOLVE workflow is the repeated evolution and reduction of model ensembles in a cascading fashion as new parameter distributions are injected in the various stages (1) through (4) and existing parameter distributions modified, frozen, or removed. A particular characteristic of the EVOLVE workflow lies in its judicious use of geomodeling and flow simulation, the use of distances, distance-based generalized sensitivity analysis (dGSA), efficient calibration to measured field and well responses, and multidimensional scaling (MDS). These are powerful concepts and are united to form a unique workflow.

The separation into four linear stages is deliberate and takes its cue from the favored approach geoscientists and engineers have used to address the uncertainty-problem in the past.
Price Scenario Analysis - Best Practices in a Volatile Price World
Authors: Allan Paul D.
Published: September 2016

E&P capital investment programs and allocation decisions can vary dramatically depending on the underlying price premise used in forecasting future cash flows. The price ‘plateau’ that developed up until the summer of 2014 reduced the criticality of robust pricing assessments in investment decisions as many projects easily met economic thresholds in that environment. Price sensitivity analysis, if conducted at all, was often based on forecast ranges intrinsically linked to the environment of the day. The significant drop in prices during the latter part of 2014 caught many investors and operators off guard, despite a history of cycles and industry memory of past price challenges. Given today's low price reality, many operators find it necessary to closely (and frequently) review their price forecasts and adjust their capital allocation programs to maintain sustainable levels of cash flow. Unfortunately, this is often a reaction to the existing price environment rather than a proactive and strategic positioning for alternative price ‘potential’. Price analysis based on revised economics and ranking, although common in the industry, often fails to yield the insights made possible through more robust portfolio-based price ‘scenario’ analysis methods. Leveraging the interaction of investment options and balancing the unique performance characteristics and timing of assets across various price assumptions can add significant value to a company's portfolio while mitigating downside exposure. This paper provides an overview of best practices in applied price scenario analysis, including methods for integrating this analysis into the ongoing business planning process, specific considerations for tools and processes required, and a case study demonstrating the application of these techniques.
The Advantages of Longitudinally Fracturing the Barmer Hill Porcellinite - A Case Study of Successfully Fractured Horizontal Wells in Barmer Basin, Rajasthan, India
Authors: Nagar Ankesh , Tibbles Raymond , Guha Rupdip , Chidambaram Prasanna , Sinha Ankaj , Pathak Shashank , Agarwal Prashant , Misra Anurag , Ranjan Amit , Ranjan Vishal , Tiwari Shobhit , Dwivedi Nikhilesh
Published: September 2016

Cairn India Ltd & ONGC completed a joint venture appraisal of the Barmer Hill (BH) field in the Rajasthan block of India in 2015. The objective was to evaluate the effectiveness of horizontal multi-frac completions. The Barmer hill field is a moderate permeability (0.5 - 4 mD) oil bearing porcellanite with alternating sequences of tight shale. To produce this reservoir economically, hydraulic fracturing was the obvious choice of stimulation and was performed on a number of vertical wells (see Shaoul et al).

To better evaluate the development strategy, completions using either transverse or longitudinal fracture treatments were successfully designed, executed, and evaluated. In the appraisal phase, four vertical and four horizontal wells were drilled to appraise the Barmer Hill reservoir in the Mangala field. Two of the horizontal wells were drilled along the maximum horizontal stress direction and completed with multiple hydraulic fracturing stages, which generated longitudinal fractures along the lateral wellbore. The fracture orientation with respect to the wellbore was confirmed with micro-seismic monitoring. This fracture treatment strategy provided the opportunity to decrease the number of frac stages and exhibited lower treating pressures as predicted by standard elastic rock mechanics theory.

While the initial productivity of the transverse fractured wells was expected to be almost 2.5 times more than the longitudinally fractured well, it only produced about 40% more. In addition, the EUR of the longitudinally fractured well is almost the same as the transversely fractured well. Based on the generated fracture geometry, theoretically these longitudinally fractured horizontal wells may also provide better effective sweep efficiency when converted to a water injector from a field development concept.
Multifunctional Fracturing Additives as Flowback Aids
Authors: Yue Zhiwei , Peng Yang , He Kai , Xu Liang
Published: September 2016

Flowback aids are usually surfactants or cosolvents added to stimulation treatments—particularly, hydraulic fracturing—to enhance cleanup of the spent fluids and ultimately improve gas or oil recovery when production begins. A range of different flowback additive chemistries have been reported in the literature containing water-wetting nonionic to amphoteric, micro-emulsion, and oil-wet components. Current unconventional reservoir surfactant technology can encounter several major challenges for use in well stimulation processes, including requirements to use nontoxic, environmentally acceptable surfactants; long-term stability at high temperature, pressure, and salinity during the hydraulic fracturing process; and minimum concentration requirements to achieve acceptable performance.

The present work focuses on the development of a new class of flowback aids package that can address these challenges. With a low treatment dosage at 1 gal/1,000 gal, they can effectively reduce surface tension and interfacial tension (with synthetic oil or crude oil). They are all "green" products, composed of 100% environmentally acceptable components and have confirmed numeric ranking using the chemistry scoring index (CSI) tool. They also demonstrated superior thermal and chemical stability to formation conditions. Column flow tests confirmed these new packages helped field oil and broken gel flow smoothly through packed formation cuttings obtained from the Permian Basin, indicating they are effective aids for fracturing fluid recovery. With careful investigation of the laboratory performance data, the final product candidate was identified. It was successfully deployed for a field trial in the Permian Basin during a harsh winter season, with positive feedback received at the early stages of production. In addition, this multifunctional additive provided the extra benefit of corrosion inhibition, which can help protect asset integrity for long-term production.
An Innovative Management Approach for Fast Track Field Development
Authors: Mata T. J.
Published: September 2016

During the last decades, upstream oil and gas industry have faced tremendous improvement due to the availability of continuous technology advances. However, there are still challenges to implement effective technology and talent management programs to tap into growth opportunities from subsurface resources in an effective manner. A successfully deployed game-changing innovation methodology embraces three main areas: discovering major key business opportunities, empowering a leader and a high-performance team focused on innovative solutions, and reengineering the business units to catalyze an agile innovation process.

Case studies from two fields located in Llanos Basin, Colombia, are presented to illustrate the power of these processes in boosting value creation with innovation. Experimentation, prototyping, and deployment of innovative technology, as well as processes and organizational initiatives, led to significant increases in production, reduction of capital and lifting costs, and reserves addition by increased recovery efficiency in a relative shorter cycle time. Furthermore, the excellent results gave way to business culture transformation in terms of new ways of collaborative work in E&P, effective knowledge sharing practices, and focused, high-return, R&D programs.

This systemic and agile approach is continuously expanding with the access to a network of extended workforces beyond the typical asset organizations, such in-company Technical Centers, specialized consultancy firms and Universities, as well as focused alliances with integrated service companies. In addition, it is essential to select and develop innovation leaders with the capabilities to mobilize the network of domain experts focused on solving complex problems, to coordinate provision of resources, to liaise with executive champions, and to communicate relentless about the business value of the early wins, and draft a strategic roadmap for full field deployment.

It is considered that the innovation management approach presented in this paper can be adapted to fulfill needs of assets worldwide.
Managed Pressure Drilling Operations in Deepwater and Total Circulation Losses Environments
Authors: Kuehn Andrej
Published: September 2016

Managed Pressure Drilling (MPD) has been widely considered as the best alternative for many drilling-related problems such as stuck pipe, lost circulation, excessive mud cost and narrow operating windows in deepwater environments. Looking for these benefits, many oil rigs has been rigged up with the MPD system, mainly because drilling engineering is emerging to even more challenging environments with the depletion of the current oil reserves. An example of that is the recent exploration of the Brazilian pre-salt fields in Santos Basin located 200km away from coast, in over 2100m water depth and up to 7000m below sea level.

Composed by huge carbonate reservoirs, the challenge to drill this porous formation has overcame the challenge to drill the two thousands meters of salt. Due to the heterogeneity of this type of formation, vugs and natural fractures are often encountered, resulting in severe or total losses experiences. Pressurized Mud Cap Drilling (PMCD) is one of MPD variations applied in situations when high rate of lost circulation occurs and can also been described as the non-return drilling method. This paper addresses a discussion regarding well control issues, application, fluid selection and safety considerations using PMCD and also the difference on the equipment alignment among this technique and others MPD methods.
Optimization of Controlled Salinity Waterflooding in Carbonates
Authors: Al Mahrouqi D. A. , Vinogradov J. , Jackson M. D.
Published: September 2016

The impact of brine composition on rock wettability and oil recovery in carbonates has been an area of research in recent years. Many studies have reported contradictory results concerning the impact of water injection salinity and composition on oil recovery. The zeta potential, which is a measure of the electrical charge at the mineral surface, is highly variable in carbonates, depending on the ionic composition of the pore water. The zeta potential controls the magnitude and polarity of the electrostatic interactions between the mineral surface and polar species in the brine and oil; it also controls the magnitude and polarity of the streaming potential, an electrical potential which arises in response to pressure gradients across saturated rocks.

Here we report the use of streaming potential measurements to characterize wettability and optimize injection brine composition during controlled salinity waterflooding (CSW) in carbonates. Crude oils, natural carbonate core samples and synthetic brines (equivalent to formation, seawater and modified seawater compositions) are used to evaluate wettability and CSW effect. We use the streaming potential measurements to determine the zeta potential, and correlate changes in zeta potential with changes in wettability and improved oil recovery. To predict the optimum brine composition for CSW requires knowledge of the zeta potential and how this responds to changes in brine composition. Such knowledge can be obtained using the streaming potential method reported here, which is much cheaper and quicker than conducting numerous multiphase coreflooding experiments and varying the brine composition on an ad-hoc basis.
Comparative Analysis of Various Failure Theories for Borehole Breakout Predictions
Authors: Morita Nobuo , Nagano Yu
Published: September 2016

Numerous papers have been published for predicting the borehole breakout problems (McLean 1990; Zoback 2007; Ewy 1999). The original theory proposed by Zoback (Zoback 2007) used the Mohr-Coulomb failure theory with a linear elastic stress strain relation. Initially, it was applied to igneous rocks and large diameter boreholes. With these original applications, the linear Mohr-Coulomb theory predicted the breakout width within a reasonable accuracy. Recently, the applications have been expanded to breakout problems for shales, mudstones and sandstones. However, there are some drawbacks. For sedimentary rock applications, the Mohr-Coulomb failure theory significantly over-predicts the breakout width. In addition, strong rocks show significant non-linearity before failure, hence, we need to artificially increase unconfined rock strength (UCS) and friction angle. The theoretical breakout width cannot be matched with the breakout width observed from the image logs unless these adjustments are made. Using the image logs and the rock strength measurements obtained from several fields, comparative analyses were conducted for various failure theories with linear and non-linear stress strains. These failure theories include Mohr-Coulomb, Drucker-Prager, Lade, Modified-Lade, Mogi and critical plastic strain. The authors also compared linear and non-linear stress strain theories. The authors estimated the increase in UCS necessary to match the breakout widths observed from the image logs obtained from several fields. The authors utilized caliper logs to compare the breakout depths as well.

The results show that if a linear stress strain relation is used, UCS must be increased artificially by 1.09-2.25 times. This increase is as much as 2.25 times for the Mohr-Coulomb failure theory. On the other hand, if a non-linear stress strain relation is used, no artificial increase is necessary except for the Mohr-Coulomb failure theory. In addition, the effects of temperature change and shale swelling are varied depending on the failure theories. These effects are supposed to de-stabilize the boreholes. Interestingly, the borehole stability differs depending on the failure theory used. Moreover, the actual breakout depths are always deeper than those predicted with a linear stress strain theory while they are shallower than those predicted by a slip line failure theory.

This paper compares the merits and demerits of each failure theory when applied to borehole breakout problems. Many triaxial tests were conducted to determine the stress strain and failure envelopes. The predicted breakout widths were compared with the measured breakout widths from the image logs. This kind of comprehensive evaluation (theoretical, experimental and field analyses) has not been performed in previous studies.
Utica Well Performance Evaluation; A Multi-Well Pad Case History
Authors: Shelley Robert , Shah Koras , Underwood Keith , Davidson Brian
Published: September 2016

Understanding Utica formation hydraulic fracture and completion effectiveness is problematic given the wide variation in geology, hydrocarbon maturity and reservoir characteristics. Quite often, a positive production response from a well may be incorrectly credited to the completion and frac design when in reality the production was dominated by favorable reservoir characteristics. Conversely a poor production response from a well may be attributed to the completion and frac design when in fact poor reservoir quality is the controlling factor. The subject of this paper are detailed analysis of three direct offset wells which were performed by experienced engineers with reservoir knowledge for the purpose evaluating completion and frac effectiveness.

When adequate production became available from these wells a detailed engineering evaluation was performed on each to estimate reservoir and frac characteristics. These evaluations consisted of (1) perform frac pressure matching for all treatments with a 3-D frac model, (2) perform production history matching on all phases with a numeric reservoir simulator and (3) estimating conditions within the fracture over time as the wells are produced. The methods used to perform these evaluations are not new, however they currently are underutalized by the industry today.

The evaluations performed indicate that completion, frac design, operational and production issues can all significantly influence Utica well production and economics. In addition the findings show that in this case the hydraulic fractures are not very efficient.1–9 This inefficiency results in a relatively short effective fracture length which causes loss of productivity, recovery and return on investment.
Geopolitics of Unconventional Resources Outside North America
Authors: Charlez Philippe A.
Published: September 2016

With the shale gas (SG) and Light Tight Oil (LTO) development, the US has become gas independent and has halved oil dependency. This revolution was based on four pillars: knowledge of the subsurface, open and competitive market, full government support and favorable mining law.

Outside the US, SG and LTO development cannot rely on the same pillars. The purpose of this paper is to analyze the motivations and the possible blocking factors that could encourage five countries/regions to develop (or not) their unconventional resources.

Gas exporter until 2004, Argentina imports today gas from Bolivia and LNG from the Middle East in a subsidized local market. These imports could ultimately stifle Argentina's public finances. Consequently, the authorities want to quickly develop the huge potential of the Vaca Muerta, one of the best source rocks in the world. Nevertheless, the cost of imported equipment and products as well as the monetary stability of the local currency could be blocking factors.

Saudi Arabia, the world's second largest oil producer, consumes nearly 1 Mbopd to satisfy the increasing electricity demand. Unlike Iran or Qatar, Saudi Arabia has not sufficiently developed its gas potential. Therefore, it intends to extract its unconventional resources in the future, in particular the source rock of the Ghawar field. Water supply for hydraulic fracturing could be a blocking factor.

China is facing a double challenge: reducing its GHG emissions by displacing its power generation from coal to gas/renewable while keeping its energy dependence at an acceptable level. Therefore, China is looking forward to develop its unconventional potential which is expected to be comparable to that of North America. The resources are located in the Tarim Basin (North West) and the Sichuan Basin (South East). The depth, the complexity of geological structures, the remoteness and the aridity of the basins make the field operations difficult and expensive.

Russia is now 70% dependent on its oil and gas revenues. The potential of Russia's unconventional resources is mainly associated with the gigantic Bazhenov formation located in Western Siberia. The Russian authorities, who wish to offset their declining conventional fields, have launched a legislative process associated with tax incentives. Permafrost and subartic conditions can be blocking factors as drilling and fracturing are required all over the year.

In the last 30 years, competitiveness in Europe was weighed down by an oil and gas bill that represents 75% of its debt. Developing the local resources to avoid becoming 100% dependent on the suppliers is of strategic importance. However, the development costs, the regional urbanization and the societal opposition are potential blocking factors.
A Step-Change for Single Well Chemical Tracer Tests (SWCTT): Field Pilot Testing of New Sets of Novel Tracers
Authors: Al-Abbad Mohammed , Sanni Modiu , Kokal Sunil , Krivokapic Alexander , Dye Christian , Dugstad Øyvind , Hartvig Sven , Huseby Olaf
Published: September 2016

SWCTTs are often used to assess residual oil saturation (Sor) or remaining oil saturation (ROS) in the near well-bore region before initiating enhanced oil recovery (EOR) or improved oil recovery (IOR) projects. The technique is based on the chromatographic separation of two different tracers. One oil/water partitioning tracer partly hydrolyzes in the reservoir, to generate a secondary non-partitioning water tracer. Most of the reported SWCTT operations typically use ethyl acetate (EtAc) as the primary tracer. Some of the challenges with the current set of chemicals used are their high flammability, poor detection limit (ppm range) and the large quantity required.

A new set of tracers has been developed to overcome these challenges. These were pilot tested in a giant carbonate reservoir undergoing peripheral water-flood to measure Sor prior to a field redevelopment project. The new tracers were field tested concurrently with the conventional EtAc method for comparison purposes. About 100 g (0.1 kg) of each of the new tracers were injected at different times and different ways during the conventional SWCTT operation. It is worth highlighting that tens or hundreds of kilograms of conventional SWCTT tracer are needed for a single operation.

This paper reviews the complete design and implementation of the test, operational issues, the analyses and the interpretation of the results. The Sor measured by each of the novel tracers compare well to that from a conventional SWCTT. The results also show that these tracers can be injected in pulse mode – at a very short time interval, thus reducing the operational time needed for pumping the chemicals. In addition, the test results suggest that several tracers with different partitioning coefficient may be deployed to investigate different depths of the reservoir.

The pilot further demonstrate that many tracers with different properties may be deployed simultaneously without risking interference with the Sor measured during the test – this may revolutionize measurements of saturations in SWCTT operations.
Cubic Law Evaluation Using Well Test Analysis for Fractured Reservoir Characterization
Authors: Denetto S. , Kamp A. M.
Published: September 2016

In fractured reservoir, the use of the so-called cubic law represents a method to describe fluid flow through fractures and to estimate effective fracture porosity from effective fracture permeability and matrix block size. The method supposes perfect fracture connectivity. In practice, however, it often underestimates field fracture porosity. This paper explores the relation between fracture porosity, fracture permeability and matrix block size using field, and in particular well test, data.

We used field data coming from four naturally fractured sand-stone reservoirs in foothills. Values of storativity ratio (ω) and inter-porosity flow coefficient (λ) coming from thirty-three pressure buildup derivatives interpretations are listed and used to estimate fracture porosity and matrix block size. The effective permeability associated to each well test, which is obtained from the stabilization of the pressure derivative, was also recorded. A non-linear regression was put in place in order to correlate fracture porosity, matrix block size and effective permeability. Obtained fracture porosities and block sizes are similar to values from other sources, such as thin section analysis and image log data.

The most significant finding is that field data can be correlated by introducing in the cubic law a correction parameter that increases fracture porosity by about two orders of magnitude. The reason for deviation from the theoretical cubic law can be threefold: first, the cubic law considers the entire hydraulic aperture of the fracture as contributing to the fluid flow, while in reality the flow may be hindered by presence of cement in-filling the fracture (thin section data supports this assumption); secondly, the cubic law assumes a perfectly connected fracture network, while in real cases some fractures may die out without intersecting any other fracture; thirdly, transient flow effects and distribution of block sizes may lead to a less well pronounced dip in the derivative, which may be interpreted as a larger fracture porosity when using a pseudo steady-state model for analysis. The correction parameter is likely not universal, and will depend on the degree of fracture in-fill and connectivity in a given field.

The work presented in this paper provides fracture permeability, fracture porosity, and block size estimates for the given type of environment. It issues a strong warning with respect to the application of the cubic law to estimate fracture porosity, and proposes a corrected cubic law expression that gives more accurate results. The methodology is useful for characterizing fracture porosity, a parameter that is notoriously difficult to measure.
Successfully Delivered Drill-In, Clay-Free Fluid with Innovative Delayed Acid Breaker for the Longest Horizontal Wells in Offshore Abu Dhabi
Authors: Angelo S. D , Shabaka H. , Hamed M. , Vinci M. , El Salam M. Abd
Published: September 2016

Extended reach drilling well design is one of the most critical designs to consider for achieving maximum reservoir contact and increasing well production. This paper demonstrates the methodology for delivering an organophillic clay-free, invert emulsion fluid system using calcium bromide in the internal phase, and discusses an innovative breaker package containing an acid responsive surfactant. Results show a significant reduction in metal/metal and metal/formation friction. Furthermore, no change in wettability has been recorded after the formation has been treated with the breaker.

Precise quantitative and qualitative testing methods provided milestone results. Phases of design began with API testing, followed by stressing the fluid beyond the normal downstream conditions, then finally using the return permeability apparatus. Testing all fluids against an artificial core, followed by a natural core, gave the operator the projections required to drill such complicated wells. Intelligent software helped to replicate the actual conditions precisely enough to drill and complete these wells with minimum friction, as well as to simulate effective hole-cleaning practices to help enable optimum equivalent circulating density (ECD) management.

From planning to execution, valuable observations were recorded. The use of this system resulted in successfully drilling and completing the longest horizontal well in offshore Abu Dhabi. During 2.5 months of drilling and completing time, no critical path time was wasted because of uncertainty or changes to the approved plan. As a result of using non-aqueous fluid, the friction factor was reduced to 0.07. Furthermore, no fluid treatment was necessary to maintain that lubricity beyond the physical properties of the system itself. The unique composition of the delayed acid breaker used in combination with acid responsive surfactant removed any skin or crushed zone around the wellbore. The recorded well producibility was beyond the expectation, and no acidizing was required.

For nearly a decade, lubricants associated with water-based fluid types have been engineered, but inver emulsion fluids had not been considered because of their low initial density and issues associated with stimulating the reservoir. This system provides a successfully designed and executed organophillic clay-free, invert emulsion fluid, as well as a state-of-art delayed acid filter cake cleanup package to maximize the return on investment.
Retrofit Gas-Lift Straddles in the North Sea
Authors: Masson Graham , Bill Bjorn , Campbell Atholl , Mackay Andrew , Brodie Alan , Emslie Murray , Isaj Albert
Published: September 2016

Deciding on the optimum design for any new well is a complex task, made often more difficult by a wide range of technical uncertainties. Getting the completion design right is particularly important for subsea wells, where the cost of intervention can be prohibitive.

After several years of production, it is common to encounter significantly different reservoir and well conditions than were initially predicted at the time of the original well completion and artificial-lift designs. Gas-lift is not always required until later in the well life. While some gas-lift valves have an impressive reliability record, some can fail or be deemed sub-optimal for the well conditions and necessitate retrieval to optimise well performance or to reinstate well integrity.

Retrievable straddle packers are commonly used to isolate water and/or gas production in the sandface completion or reinstate well integrity in the upper completion. This paper will review different methods used to reinstate gas-lift, and describe the gas lift design process and straddle configuration using case studies from the North Sea.

In particular, Premier Oil undertook a subsea well intervention campaign to restore production, which had ceased following the suspected failure of the gas-lift system. Analysis of the well performance data suggested that one or more gas-lift valves were inoperable and that the original valve depths were not ideal for the encountered reservoir conditions.

The operation was performed from a light well intervention (LWI) vessel, deploying a retrievable Interwell straddle and PTC GoLift™ Straddle system, installed in the tubing across and between the existing side pocket mandrels, creating a retrofit, triple packer, gas-lift straddle.

Premier performed a safe and successful LWI operation, returning the well back to its full production potential, having met all well intervention objectives. Running the retrievable straddle packer solution with PTC's GoLift™gas-lift system helped to optimise production and saved the need for a costlier rig-based upper completion workover.

This paper will further look at the design and development of these technologies, examine in depth one case study for the Brenda D3 design and installation.
Successfully Developing Fields in a Mature Region Whilst Revenues are Going Down, a Non-Operating Partner Perspective
Authors: Schulte Ruud , Kreft Eric , van Ewijk Eric
Published: September 2016

EBN - the Dutch state-owned Oil and Gas Company - has been working with a large number of International Oil Companies, (super)majors and smaller independents, that have been active within The Netherlands.

Over the years, field developments have become increasingly challenging as opportunities are smaller in volume and technically more complex; the low hanging fruit has already been picked. Since late 2014, the difficulty to bring remaining opportunities into production is exacerbated by recent oil and gas price trends.

E&P companies have learned from historic project performance and from each other, resulting in project management systems that in essence are look-a-likes. A typical project management system consist of a three stage gated approval process with a focus on good Front-End Loading, a focus on project team staffing, and on other Best-Practices. Although at least on paper each individual project is undergoing extensive reviews at all the different gates, in reality our research observed significant differences in actual adherence to the proscribed work processes, not only by company but also between projects. This variety results in a wide range of project performance: from very successful to train wrecks.

In 2012 our Non Operated Ventures (NOV) management system was overhauled in order to stimulate the profitability of our field developments. Changes made included an earlier-on involvement to ensure that a broad range of concepts is being considered with an emphasis on novel cost-efficient concepts. Finding the delicate balance between hands-off, eyes only has contributed to a drastic improvement in project performance with demonstrated costs savings of up to 50 %. Cost savings that –given the current price trends - are required to be able to sanction and commercially successfully execute forthcoming field development plans.

This paper will discuss in detail our look back analysis, including earlier projects with typical E&P project results (cost and schedule overruns and the like), but also the results of recently more successfully completed projects and most importantly; the drivers that make the difference.
A Region-Based History Matching Approach Using Data-Driven Modeling Techniques
Authors: Mital M. , Verde A. , Saputelli L.
Published: September 2016

History matching is an important inverse problem extensively used to estimate petrophysical properties of hydrocarbon reservoirs by matching a numerical simulation to the reservoir's history of multiphase flow production. Modern history matching strategies pose the characterization process as an optimization problem involving the estimation of rock properties such as porosity and permeability in all grid blocks (Ng) of a petroleum reservoir model. However, when large number of cells are considered these strategies becomes highly inefficient requiring large number of computational expensive reservoir simulations and even being inadequate, from an optimization point of view, when static data is not abundant or unreliable leading to ill-posed situations.

This work proposed a novel approach to reduce the complexity of the inverse problem in several ways by: i) focusing exclusively on characterizing rock properties within certain regions of interest (Nr where Nr<<Ng) in the reservoir model (instead of at every grid block) where either high level of uncertainty exists or exploration wells are expected to be drilled, ii) parameterizing spatial distribution of rock properties using kriging techniques based on data available only at particular locations in the reservoir (in special at the center of predefined regions of interest), iii) replacing the time consuming reservoir numerical simulator by a surrogate model constructed using only input and out data, iv) efficiently generating multiple realizations of property distribution (input data) employing well-known design of experiments techniques and forecasting well production response (output data) associated to those realizations using an open source and multi-purpose numerical reservoir simulator tool (MATLAB Reservoir Simulation Toolbox, MRST®) as well as Ecrin®, and v) constructing a computational cheap surrogate model employing data dimensional reduction techniques.

Using synthetic two-dimensional and multiphase numerical examples of increasing level of complexity involving several thousands of unknowns, the accuracy and computational performance of the proposed region-based history matching methodology was evaluated. The novel approach reduces the size of the optimization problem to a fraction of unknown parameters and the results showed it can be used effectively and efficiently for estimating petrophysical reservoir parameters with acceptable accuracy when static reservoir data is limited in the absence of previous characterization efforts. The novel approach seems also flexible enough to incorporate known geological properties of the reservoir by constraining the optimization problem and the results can also be directly used as a first solution approximation in more detailed characterization projects.
Large Scale Testing & Modelling for Cement Zonal Isolation of Water Injection Wells
Authors: Therond Emmanuel , Bois Axel-Pierre , Whaley Kevin , Murillo Rodrigo
Published: September 2016

Water injection into soft sand is a global industry challenge due to the complex problem of maintaining sustained water injection rates into the desired reservoir. Drilling, Cementing and Completion engineers are addressing each technical and operational aspect of water injectors, including cement isolation. Cement serves as a barrier from well construction to post abandonment. It contributes to ensuring no out of zone water injection occurs due to flow behind casing. If water does go out of zone, new drilling hazards due to water breaching and loss of reservoir management will occur.

At present, as far as we know, the industry does not have a systematic methodology for defining and verifying the required physical and mechanical properties of the cement to endure water injection service and retain its isolation capability during well life. Cement integrity simulators (CIS) provide different answers, mainly because they all assume a d ifferent initial stress state in the cement after hydration. As a consequence, a new CIS model that computes this stress state has been developed, along with a large scale testing setup to validate its predictions.

The new model incorporates key design parameters of effective CIS models. 1) The initial stress state after cement hydration is computed; 2) Varying loadings the cement sheath is submitted to are simulated; 3) The elasticity, plasticity, and failure of materials is taken into account; 4) The simulations are fast enough to facilitate sensitivity analysis; 5) The model outputs allow visualization of cement integrity across the entire length of the cement sheath; adjacent to both reservoirs and seals.

In parallel to the modelling work, a large-scale test apparatus was built to evaluate cement zonal isolation under water injection pressure and temperature conditions. Its objective was to generate pressure and temperature cycles inside sections of cemented casing assemblies to replicate the conditions of pressure and temperature variations in a water injection well.

The results of the test confirmed the accuracy of the new CIS model. It also showed that cooling due to water injection had a bigger impact on cement integrity than increasing pressure. Additionally, it showed that micro-annulus generation had more effect than tensile cracking in terms of cement barrier permeability increase.

Based on this work, cementing design workflow for zonal isolation of water injectors has been established. As injection pressure and temperature, rock properties, confinement pressure and completion type vary from well to well, zonal isolation for water injection wells must be designed on a case-by-case basis. New cementing workflows for water injection wells involve rigorous cement mechanical property testing and cement stress modelling.
Horizontal Steam Injection Flow Profiling Using Fiber Optics
Authors: Shirdel Mahdy , Buell R. S. , Wells Mike , Muharam Cece , Sims Jackie
Published: September 2016

Steam conformance control in horizontal injectors is important for efficient reservoir heat management in heavy oil fields. Suboptimal conformance and non-uniform heating of the reservoir can substantially impact the economics of the field development, oil production response and result in non-uniform steam breakthrough. In order to achieve the required control, it is essential to have an appropriate well completion architecture and robust surveillance.

Five fiber optic systems, each utilizing a unique steam conformance control completion configuration, have been installed in two horizontal steam injectors to help mature steam injection flow profiling and conformance control solutions. These fiber optic systems have utilized custom designed fiber optic bundles of multimode and single mode fibers, for distributed temperature sensing (DTS) and distributed acoustic sensing (DAS) respectively. Fiber optic systems were also installed in a steam injection test flow loop. All the optical fibers successfully acquired data in the wells and flow loop, measuring temperature and acoustic energy.

A portfolio of algorithms and signal processing techniques were developed to interpret the DTS and DAS data for quantitative steam injection flow profiling. The heavily instrumented flow loop environment was utilized to characterize DTS and DAS response in a design of experiment matrix to improve the flow profiling algorithms. These algorithms are based on independent physical principles derived from multiphase flow, thermal hydraulic models, acoustic effects, large data array processing, and combinations of the foregoing methods for both transient and steady state steam flow. A high-confidence flow profile is computed based upon convergence of the algorithms. The flow profiling algorithm results were further validated utilizing a dozen short-offset, injector observation wells in the reservoir that confirmed steam movement near the injectors.
A Study into Prediction of External Casing Corrosion from Contact with Overlying Aquifer and Injection Waters
Authors: Farooqui Mohammad , Marmoush Mohammed , Aly Maher , Pacheco Jorge , Morrow Timothy
Published: September 2016

This paper presents the methodology and findings from a study to assess the external corrosion rates in an offshore field from contact of the casing string(s) with aquifers and/or water injection zones overlying the production reservoir. The study objectives were to gain a better understanding of indicators of contact between the water and the casing strings and then to assess the corrosion risks that this presented.

A key indicator of contact between formation water and the casing was elevated Gamma Ray recorded across the interval when compared to a base log. The elevated Gamma Ray recording is indicative of scale deposition on the casing string and scale modelling tools were utilised to assess the potential of inorganic salt deposition on the casing strings. In the absence of reliable logging tools that can provide quantitative measurement of metal loss due to external corrosion through multiple strings, this study utilised a proprietary corrosion modelling software to assess the possible minimum and maximum corrosion rate range based on the limited information on water composition and the content of dissolved acid gases (H2S and CO2) in the formation fluids.

The paper provides suggestions to identify potential locations of contact between corrosive aquifer waters and the wellbore from routine production logging data. It identifies critical subsurface data required for a realistic assessment of external corrosion damage to the casing strings in the absence of effective logging tools to measure actual metal loss trends.