Devex 2015 Posters

Posters at Devex 2015


Effect of stress anisotropy on thermal fracture modeling

Cas Berentsen, Hans de Pater
Fenix Consulting Delft, Delft, The Netherlands

Prediction of thermal fracture size can be accomplished with models that couple reservoir flow and fracture propagation. As a worst case, the model will assume a single planar fracture propagating from the injection well.

Cold water injection results in cooling of the reservoir rock which reduces the stress. In case the stress falls below the reservoir pressure, thermal fractures will propagate. In stiff reservoirs, cooling may even cause thermal fractures to open without injection.

Fractures induced by high rate injection require a balance between fracture leak-off and fracture propagation. The thermal fractures will however only propagate when sufficient rock has been cooled around the fracture. However, the cooled zone can be fairly narrow, while still giving sufficient stress reduction for fracture propagation. The elongation of thermal fractures typically increases with injection rate, but does require some level of stress anisotropy. In case the stress anisotropy is small the maximum horizontal stress will turn tensile as well resulting in transverse fractures and more circular growing fractures.

A model that adopts a single planar fracture assumption does not allow for transverse fracture growth at all and generally overestimates fracture growth. In case the stress anisotropy is small this is unrealistic, even at relative high injection rates.

We will show several cases of thermal fracture modeling illustrating a realistic approach to modeling waterflood fractures by allowing for transverse fracture growth.


Results of the 5th Well Intervention Excellence Network (WIEN) – 2010-2014

Janine Jones
Oil & Gas UK, Aberdeen, UK

This paper sets out to provide an update to the results of the 4th Well Intervention Excellence Network (WIEN) – 2010-2013. It aims to provide a comprehensive analysis of the key well intervention trends derived from the full WIEN database across 2010-2014. The data from 2010 to 2013 assessed more than 5,300 European well interventions. This year, data from an additional 2,000 well interventions is anticipated, and the data collection will be expanded to include new areas of interest. The analysis will build on that done over the previous four years and new methodology for analysis, such as identifying year-by-year trends, will be introduced. The data will be aggregated, and the results used to highlight common intervention issues in mature basins. This paper will allow readers to benchmark well interventions across onshore and offshore well environments against technical success rate, intervention type and contribution to production.


Investigation of oil-mineral interactions and their impact on waterflood oil recovery using lab-on-a-chip methods

Blessing Akamairo, Stephen A. Bowden, Yukie Tanino
University of Aberdeen, Aberdeen, Scotland, UK

It is well established that reservoir wettability plays a significant role in determining the efficiency of waterfloods. However, work to date have largely focused on explaining waterflood recovery in terms of contact angle, which is used to characterize the wetting behaviour of the rock at the pore scale. However, contact angle – like reservoir wettability – is in turn a product of more fundamental geochemical properties of the system, namely mineralogy, oil composition, and connate and flood water composition. At present, we are still unable to predict contact angle – hence waterflood recovery – from basic geochemical data typically acquired during exploration.

In this study, we compare the pore-scale distribution of oil and the incremental volume of oil produced during waterflood for different combinations of mineralogy and crude oils using lab-on-a-chip methods. We measured fractional flow as a function of oil chemistry, mineralogy, and flow rate. In quartz-rich porous media, oils of similar acidity and density exhibited oil-wet behaviour during waterflood. However, in calcite, one oil switched to a water-wet during waterflood whilst the other oil did not. These results indicate that oils that have similar thermophysical properties may still give rise to large differences in waterflood recovery.


A collaborative process to create a consistent and quantitative cement bond and zonal isolation evaluation workflow

Callum Anderson
ConocoPhillips, Aberdeen, UK

Given the North Sea has been producing hydrocarbons since 1975 and the maturity of the basins, it is unsurprising that rig activity to decommission and abandon wells is steadily increasing. ConocoPhillips have recently begun their abandonment campaign of over 170 wells across the Southern North Sea, and, similar to other operators, are required to satisfy well integrity criteria and regulations that are put in place by governing bodies as well as their own internal standards to ensure abandonments are robust and fully compliant.

One of the many important criteria for well abandonment is to ensure there is an acceptable cement bond quality, over specific intervals, which satisfy zonal isolation requirements. Historically, cement bond logs have been adopted to determine isolation quality but interpretation has typically been more qualitative than quantitative.

This presentation describes a process to define casing and cement specific cut-offs, which can be applied to standard cement bond logging tools measurements, to quantitatively define good cement bond and zonal isolation. Collaboratively working with Halliburton Wireline,this process has been implemented into their internal software. This workflow has allowed for consistent cement bond interpretation from one well to the next, giving the ability to quickly and efficiently run sensitivities on cut-offs and re-run interpretations. This process has dramatically improved the reliability and speed of evaluation and allows for near-real time decisions thus avoid operational hold ups and lost rig time.


Imaging Subsurface Targets without the Overburden

Matteo Ravasi, Ivan Vasconcelos, Andrew Curtis, Alexander Kritski, Carlos Alberto da Costa Filho, Giovanni Angelo Meles
University of Edinburgh, Edinburgh, UK, Schlumberger Gould Research, Cambridge, UK, Statoil, Trondheim, Norway

Identification and characterization of subsurface reservoirs in the presence of complex geology has long presented a challenge to industry. A crucial step for any imaging technique is the estimation of wavefields within the Earth’s interior where no real observations are available. Standard estimation or ‘redatuming’ approaches generally fail to explain how energy propagates in the complex shallow subsurface unless high-resolution velocity models are available, and do not accurately predict multiples in the subsurface.

The new method of Marchenko redatuming promises to reconstruct accurate subsurface fields computationally, while still using relatively little information about the Earth’s subsurface properties. Primaries and internal multiples can be estimated with correct amplitudes in an iterative fashion, using only reflection measurements at the Earth’s surface and a smooth velocity model. While the first iteration is closely connected to classic redatuming methods, subsequent iterations identify those events which are incorrectly handled by such methods, and adjust their kinematics and amplitudes. Constructed wavefields can then be used to synthetize a local reflection response in the subsurface free of spurious events related to internal multiples in the overburden, thus forming a basis for obtaining accurate images of target zones at any depth level of interest.

Using both a synthetic and a real dataset acquired over the Volve field, we demonstrate that Marchenko redatuming outperforms conventional methods in estimating subsurface fields and we show how such improvements can lead to more accurate and detailed images of target areas in the deep subsurface without requiring any detailed model of the overburden.


Ensuring continuous production at maximum flow rates in solids producing wells

Neil Meldrum
FourPhase AS, Os, Norway

In the Oil and Gas Industry the three phases – oil, gas and water – are well known and well taken care of. FourPhase is focussing on the fourth phase – solids. In both mature and new fields where solids are present, we turn the management of solids into a key performance indicator that is fundamental to improved production performance.

With the challenges of low oil price, high lifting costs and a maturing basin, the UK Oil & Gas Industry must focus on working smarter and more efficiently. There has never been a greater need to apply new technology and implement innovative solutions in order to reduce operational costs. Solids removal technology plays a major role in materially reducing costs and improving production efficiency.

This paper will investigate different challenges related to solids removal management and will present a patented technology developed by FourPhase which turns these challenges into continuous production opportunities. A case study will be presented investigating practical applications of continuous production and solids removal systems and the economic impact to the customer, in this case Statoil.


The Nature of the Central North Sea High Pressure System

Kingsley Nwozor, Gareth Yardley
University of Aberdeen, Aberdeen, UK

Many wells have been drilled in the Central North Sea; however, it remains a challenge to understand the high pressure system, particularly the pressure transition zone from relatively low pressures at the top of the Chalk Group, to extremely high pressures in the deep Jurassic and Triassic reservoirs. Uncertainty about the nature of the transition zone makes assessment and drilling of the deep prospectivity difficult. Several models of the pressure transition zone have been proposed. In this study, log, drilling and measured pressure data have been analysed by several methods including a new tool: the Late Geopressure Indicator (LGI) in order to understand the onset, magnitude and causes of the high overpressures. It is shown that disequilibrium compaction is dominant in the Cenozoic mudstones where its magnitude is related to recent burial while late geopressure dominates in pre-Chalk formations. Below the Chalk, both the total overpressure and proportion of overpressures due to late geopressure mechanisms increase with depth into the Central Graben. Overpressures range from approximately 2000 psi (15% from late mechanisms) at the basin margins, to 8000 psi, (80% from late mechanisms) in the deepest parts of the basin. Some models for the pressure transition zone indicate that the Chalk Group is the ultimate seal to the pressure system; however, it is demonstrated that the top of the pressure cell can be anywhere between the Chalk and Heather Formation and its location depends upon the thickness of the sealing lithologies between the Base Chalk and the top reservoir.


Gas Flow through Unconventional Gas Reservoirs

Chariton Christou, Kokou Dadzie
Heriot-Watt University, Edinburgh, UK

Unconventional gas reservoirs consist of porous structure with diameter of pores in the range of some nm to μm. In these scales, with high pressure-temperature flow, pores diameter become comparable to the gas mean free path. These reservoirs flow; fall often in the transition and slip flow regime. Standard continuum fluid methods such as the Navier-Stokes-Fourrier (N-S-F) set of equations fails to describe flows on these regimes while molecular dynamics (MD) become exorbitant. Kinetic theory such as Boltzmann equation must be adopted in order to describe the fluid properties. We present a Direct Simulation Monte Carlo study of a 3D porous structure (sandstone) in an unlimited parallel simulation and we describe the gas properties in shale gas reservoirs. The three-dimensional geometry was obtained using a microcomputed–tomography (micro CT) scanner with a resolution in the scale of some μm. Pressure driven flow is studied on these scales for various Knudsen numbers and compared with N-S-F.Our findings demonstrate that significant differences appear in gas properties depending on the method that it’s been used (N-S-F vs D.S.M.C). The intermolecular collision model and the gas surface interaction model (Specular vs Diffuse) also affect the gas properties. Our results show that, in lower Knudsen number (Hydrodynamics Regime-Conventional Reservoirs) the two methods show similarities, while in transition and slip flow regime noticeable difference can be seen in velocity profile between Navier-Stokes-Fourrier and Direct Simulation Monte Carlo.The importance of the simulation is also compare to conventional methods that are used in our days for gas reservoirs.


Maximising the Accuracy of Flow Rate and Reservoir Description of an Intelligent Well’s Multiple Producing Zones through Real-Time, Well-Test Design

Reza Malakooti, Khafiz Muradov, David Davies
Heriot-Watt University, Edinburgh, UK

The value added by intelligent wells (I-wells) derives from real-time, reservoir and production performance monitoring together with zonal, downhole flow control. Optimal production control using direct measurements of the I-well’s zonal flow rates are not normally available. In practice the zonal, Multi-phase Flow Metering (MFM) parameters are calculated from indirect measurements, such as pressures, temperatures and total well flow rate.

To-date, all published techniques of zonal flow rate allocation have been “passive” in that they calculate the MFM parameters for a fixed, known completion configuration. These techniques are subject to model error, but also to errors stemming from measurement noise when there is insufficient data duplication for accurate parameter estimation. This work describes an “active” monitoring technique which uses a direct search method based on the Deformed Configuration algorithm to optimise the sequence of Interval Control Valve positions during a routine, multi-rate flow test.

This novel approach defines four monitoring levels, or combinations, of the available downhole and surface measurements to maximise the accuracy of the calculated MFM parameters. Level one requires the least amount of reservoir and well data; while level three requires the most complex data set, but provides in return an increased understanding of the reservoir and reservoir fluid properties.

Our “active monitoring” workflow can be extended to a wide range of production and injection allocation problems for any well completion type. The workflow may also be used to improve the accuracy of production flow rate measurements and, ultimately, to maximise oil production rate and recovery.


Understanding production backout in the subsea pipeline network of the Pelican Field in the Northern North Sea

Andrew Bostock, Eoin McPherson, Mausam Gaurav
TAQA Bratani Ltd, Aberdeen, UK, Integrated Production Technologies Ltd, London, UK

The Pelican Field is a sub sea oil development tied back to the Cormorant Alpha platform, located in the Northern North Sea. TAQA took over operatorship of this asset from Shell in 2008.

Production from the wells is collected via a flow line network to a subsea manifold and then routed via two pipelines to the Cormorant Alpha Platform, which is located 12 km away. The Pelican wells are gas lifted, the field is water flooded and the volumes of water, gas and oil producing through the subsea system have a considerable effect on the production behaviour. Some wells are not normally produced, both due to technical issues, but also because the production from these wells is considered to be backed out. Backed out production is the effect of a well giving zero or negative total system increment despite the well having positive through well bore oil production. The backout situation was exacerbated when a new part of the field was discovered in 2013 with well PU-P22S1 and the strong production from this well increased the effect of back out on the other wells.

This presentation will explain TAQA’s efforts to understand the effect of backout in the Pelican system. The building of the network model and calibration with real operational data will be discussed, as will its capability to predict observed events. The presentation will also elaborate on long term forecasting with a network model, gas lift optimisation, and investigate the effect of future development wells on the existing producers.


Towards Improved Performance in Directional Drilling

Przemyslaw Kukian, Daniel Minett-Smith, Vincent Coveney, Ian Milsom
Weatherford, Tewkesbury, UK, Bath University, Bath, UK

Directional drilling improvement has been and will continue to be an important factor in obtaining more complete oil and gas recovery from the formation. The paper will review past work and describe results from a new industry-academic research project studying the effects of loading and constraints on 3-D deformation and strain in the bottom-hole assembly (BHA) in relation to performance of point-the-bit rotary steerable systems for more precise control and increases in dogleg severity. The emphasis here is on quasi-static aspects of behaviour.

Previously published experimental work has pointed to limitations in existing theory and numerical modelling of buckling of the drillstring. In particular, buckling was reported to occur at much lower axial loads than was predicted by mathematical models.

Work from an industry-university project is described. In the current work, mathematical models are reconciled with experimentally observed behaviour: by systematic examination of the effects on BHA 3-D behaviour of contact constraints, gravity and consequent bifurcation structure; and by more precise control of experimental conditions than previously used and more complete and precise measurements than previously reported.

Results are also reported for very complex loading cases involving a point-the-bit rotary steerable system (RSS).

Practical implications of the study are discussed.


Overcoming New Challenges for Elastomer Components in High-Temperature High-Pressure Hostile Environments

Przemyslaw Kukian, Vincent Coveney, Daniel Minett-Smith, Ian Milsom
Weatherford, Tewkesbury, UK, Bath University, Bath, UK

Drilling for oil and gas and their efficient extraction from reserves relies on the correct functioning of many elastomer components. Conditions down hole, already demanding, are set to become yet more extreme – especially for elastomer components, putting them under threat. Meeting this step change in demands requires a corresponding step change in approach.

The qualitative and quantitative nature of the challenges facing elastomer components in high-temperature high-pressure hostile environments down-hole are analysed. Previous academic and industry-based work is reviewed.

The functioning and durability of an elastomeric pressure-balancing diaphragm, a key component in a point-the-bit rotary steerable system (RSS), is given as a particular example. It is demonstrated that the new challenges include increases in mechanical demands as well more extreme temperatures and more hostile chemical conditions.

Fresh theoretical and experimental approaches and results, together with field analyses, are described from a joint industry-university project addressing the above challenges.


Petroleum, Energy, Uncertainty: Navigating the Crossroads Ahead.

Erik Dalhuijsen
OceanValley Ltd, Aberdeen, UK

Our industry’s contractive reaction to the recent oil price drop is predictable, but is such a response preventable? Belying a substantial history of long term predictive scenarios, in recent decades we have shortened the horizons, slowly re-defining our industry in ways which simplify the complex interaction models but marginalise realistic long term scenarios, reducing resilience and stability. Driven by these narrower definitions we appear to account for an ever smaller circle of external influences, risks and trends. Are we matching our business environment to our restricted concepts, instead of maximising opportunities by anticipating and embracing change and uncertainty?

Releasing this restricted definition and taking a broader and longer view of the business environment we operate in, the presentation considers the large external factors, investigating which parameters and uncertainties really matter to the industry. It sheds light on wider issues including price levels and predictions, political climate change scenarios and future energy market developments, showing how and especially when these may substantially influence the industry’s playing field. It explores directions an industry focussed on the future could be looking into, giving examples of opportunities and paths walked before.

This refreshing look at a larger yet relevant dataset should lead to insights on choices available, in support of an aspirational track for our industry: challenging, exciting, feasible, and reaching far beyond its current course.


The Improvement of Production Profile While Managing Reservoir Uncertainties with Inflow Control Devices Completions

Mojtaba Moradi Dowlatabad, Faraj Zarei, Morteza Akbari
Heriot-Watt University, Edinburgh, UK, Baker Hughes Inc., Houston, USA, CMG Europe, London, UK_

Advanced Well Completions (AWCs) are capable to mitigate the unpredictable production conditions particularly in case of the heterogeneous reservoirs. Identifying the optimal design of the wells involves employing approaches based on the predictions of reservoir and well models. However, various parameters such as the petro-physical properties, fluid contacts, aquifer strength etc. in the reservoir models are always associated with uncertainty to some extent. This requires implementing probabilistic approaches important for the field’s performance prediction.

Latin Hypercube sampling approach was applied to evaluate various dynamic uncertain parameters. Numerous realisations of the reservoir models were also generated to provide a confident level of geological uncertainty by a sequential Gaussian simulation algorithm. The performances of Open-hole and (Autonomous) Inflow Control Devices [(A)ICDs] in horizontal wells were compared to investigate the uncertainty management by the completions.

The overall as well as the individual impacts of the uncertain parameters on oil production profile were evaluated by statistical analysis. This helps determining the most influencing parameters on the production profile as well as the most influenced uncertain parameters when AWCs are deployed. The results showed that although both of the AICDs and ICDs completions significantly reduce the oil production variations comparing with Open-hole completion, AICDs completions perform much better than the ICDs to manage the reservoir uncertainties impacts on the oil recovery.

The study aims at providing approaches quantifying the impacts of AWCs on the reservoir uncertainties and confirming the long-term benefits of AWCs while reducing the risk associated with the field’s development plan.