bluuebunny/crossref_metadata_2025 huggingface dataset:
Integrated Gas Development Planning in Southern Iraq
Authors: Karnik Amit A , Gupta Arjit , Wharton Mark , Henry Herve
Published: September 2016

Maximizing the value of a significant gas resource base in southern Iraq for all key stakeholders is complex, driven by a number of key challenges on both the supply and demand-side of field development. The majority of the future gas supply in the south of Iraq will come from associated gas from some of the world's largest oil fields including Rumeila, West Qurna and Zubair). Successfully utilising the gas for industrial and domestic supply requires integration across upstream, midstream and downstream business segments and cooperation between multiple parties from the Government of Iraq (GoI) and the field operator contractor consortiums in Iraq.

Some of the main challenges that the Iraq Oil & Gas industry faces today are lower commodity prices impacting the availability of investment capital, weak fiscal incentives for gas production, inadequate integrated gas infrastructure development, limited cross-industry gas planning and coordination & limited new exploration activity. The above issues also cary an overlay of environmental and security conditions, meaning that fully integrated development planning and decision framework modelling needs to be at the core of mapping the most attractive way forward for future investments.

This paper presents an integrated workflow approach that allows modelling & assessment of the impact of technical as well as non-technical risks and uncertainties in a systematic manner along the value chain at a number of different nodes. This model follows the hydrocarbon molecules from the reservoir through to the downstream petrochemical plant enabling assessment of a potential range of scenarios across upstream, midstream and downstream.

In a region where uncertainties go far beyond the technical domain, this approach allows decision makers to navigate through the potential outcomes and formulate integrated roadmaps and development strategies. It also identifies the benefits of an integrated development approach across fields developed by different contractor consortiums. The workflow facilitates; Analysis of the current gas landscape and identification of priorities, with a focus on what could be done to increase gas supply in the short to medium term;A vision for longer term gas industry development and provides guidance on nature and timing for future infrastructure required to realize this visionIdentification of key enablers to expedite gas growth in the wider southern Iraq area.
A Road Map to Improve Coiled Tubing Well Intervention Services
Authors: Ginest N. , Al-Nuhayan F. , Ashby S. , McClelland K. , Phillips J. , Green T. , Winkleman D.
Published: September 2016

Saudi Aramco performs over 900 coiled tubing (CT) well intervention operations annually on oil, gas and water wells. To improve service quality and reduce incident frequency, Saudi Aramco has focused on developing internal resources, setting realistic standards and assessing service providers. Sharing the processes followed, lessons learned and reoccurring service quality issues should be of value to the practicing engineer.

Saudi Aramco has developed a comprehensive CT well intervention program with the goal of ensuring that all CT operations are conducted safely and effectively. The foundation for this integrated, knowledge and quality based CT well intervention program was built on the following principal components: The compilation and periodic revision of two comprehensive internal reference documents – the Saudi Aramco CT Manual and the Saudi Aramco Standards for CT Services. These documents are applicable company-wide for rig based and rigless CT operations in oil, gas and water wells. The manual and the standards focus on safe CT operations and maintaining full control of the well with multiple redundant closed and closeable barriers.The commitment of Saudi Aramco's Upstream Professional Development Center (UPDC) to be an industry leader in the accelerated training and development of upstream professionals. UPDC's instructional design experts worked closely with internal and external subject matter experts (SMEs) to design CT courses to enhance learning and maximize relevance to job designs and operations taking place every day within the company.A program to conduct comprehensive technical and quality management system (QMS) assessments of well intervention service providers was initiated to address concerns about the quality of the well intervention services provided by both current and future providers and to ensure that operations are conducted safely.

The program was initiated over 15 years ago and has grown and evolved based on advances in the industry and lessons learned internally. What started as a narrowly focused manual to cover CT operations in high pressure gas wells has expanded substantially to include all CT operational categories, training, quality management systems and assessments. This paper will discuss details of the implementation of the three primary components of Saudi Aramco's integrated approach. Statistical trends of CT failures will be presented as a measure of the program's success, and the results and an analysis of the findings from the comprehensive CT service provider assessments will be discussed.

Instituting technical and quality standards, measuring compliance with these standards by performing periodic assessments, and providing training for the end users have resulted in lower incident rates and better delivery of service related product.
Evaluation and Development of Complex Clastic Reservoirs using NMR
Authors: Hursan Gabor , Silva Andre , Zeghlache Mohamed L.
Published: September 2016

Several light oil and gas reservoirs are present within an extensive Permian clastic sequence in the Middle East. Well logs and core data revealed numerous challenges for the petrophysical description of this formation. Rapidly changing depositional environments and diagenetic effects caused heterogeneities in grain size and sorting within clean sands. Consequently, gamma ray and conventional porosity logs have little sensitivity to rock quality variations. Secondly, an influx of meteoric water into the reservoir rocks decreased formation water salinities which adds uncertainties to the estimation of fluid saturations from resistivity logs. Finally, gas-oil contacts are present in some reservoirs where log-based in-situ hydrocarbon typing is of great practical value. The introduction of nuclear magnetic resonance (NMR) logs has successfully mitigated these issues as evidenced by petrophysical interpretations and formation testing in the area's exploration and delineation wells.

Lateral facies variations and complicated reservoir structures warranted the deployment of NMR technology in horizontal development wells for better well placement and completion optimization with logging while drilling (LWD) NMR as the most preferable option. The NMR logs led geosteering decisions and proactive well planning to singificantly increase reservoir contacts in producer wells. Permeability predicted by the NMR logs is of great value in real-time well placement decisions and completion design including ICD installations. The low-gradient LWD NMR measurement gives rise to a very simple and robust real-time fluid identification thanks to the the good separation of water and oil signals in the NMR T2 spectrum. This fluid quantification, combined with bound fluid analysis, helps determine the well's position in the transition zone by detecting free water.

This paper summarizes the experience with both wireline and LWD NMR technologies in the area. Lessons learned include considerations for deployment, tool activations and NMR interpretation.
Loose Coupling of Metadata and Actual Data in End-to-End Data Provenance
Authors: Rundle R. T. , Vuurboom R. , Monroe B. V.
Published: September 2016

In a distributed object system, metadata provides a concise description of the object that can be distributed broadly. The actual data that represents the complete object is often very large and hence can be time consuming to transfer. Metadata is an enabler for the wide area distribution of objects along potentially unreliable and low speed channels. The metadata could go first and the actual data would follow only if needed.

Data provenance is the chronology of an object, i.e. a record of all of the transformations and actions that modified the state of the object from the time of creation to the present time. End-to-end data provenance is the ability to account not only for the data provenance of a single object, but also to account recursively for the data provenance of all other objects that affected the state of the object.

Loose coupling of metadata and actual data is well understood for static, unchanging data. Systems across many industries allow remote browsing of metadata representing huge datasets and the selective movement of actual data. For example every content delivery network (CDN) employs loose coupling of metadata and actual data to deliver movies, videos, books and other types of static data.

The problem yet to be solved is the one in which the actual data is changing over time. This is an important use case in shared earth problems. As modeling of the subsurface increases and is used by larger, more geographically disperse teams, there is a need for a system that supports the special requirements of shared earth modeling. These requirements include the need to support parallel changes to objects, support for slow and unreliable networks, and the ability to work disconnected from a central repository. Such a system is presented in this paper. This paper is a follow on to SPE 174803, End-to-End Data Provenance.
Determination of Oil Well Production Rate by Analysis of the Real-Time Dynamometer Card
Authors: Han Guoqing , Tan Chaodong , Li Jun , Pan Zhejun , Zhang He , Ling Kegang
Published: September 2016

Real-time data collection, processing, and surveillance are critical in field operations for monitoring well production and assessing effectiveness of well workover and intervention. Conventional metering strategy is unable to keep up with the requirement for continuous and real-time measurement. For marginal fields, surface facility is often shared among many wells due to its high cost. In this paper, an innovative technology is proposed to analyze dynamometer card collected from a SCADA system and accurately derive the individual well production rate in real time.

By solving wave equations, the developed system converts the surface dynamometer card to a downhole dynamometer card, which can be analyzed to locate the travelling valve opening and closing points. With non-linear and unconstrained optimization, this technology can accurately determine the effective stroke and liquid leakage, and consequently obtain the production rate.

The proposed method has been successfully applied to 170 oil wells with an average measurement error of only 6.66%. It works well for both vertical and deviated wells, and for both light and heavy crude fluid. This digital energy technology can be used not only to determine the production rate for individual wells in real-time, but also to decrease operational expenditure, which can significantly improve the cash flow for managing marginal fields in the current low oil price environment.
Oil Price Shocks: A Measure of the Exogenous and Endogenous Supply Shocks of Crude Oil
Authors: Economou A. , Agnolucci P.
Published: September 2016

The paper introduces a new measure that jointly identifies and disentangles the oil supply shocks of crude oil into exogenous and endogenous, by quantifying the positive and negative shocks to oil production caused by events outside the oil market (exogenous) or as a consequence of the normal functioning of the oil market (endogenous). The objective is to examine how the use of alternative measures of oil supply shocks affects our assessment of the dynamic effects of supply shocks on the real price of oil since 1990. Results show that for most of the 1990s, shortfalls in oil production that were brought about by geopolitical episodes accounted for about 7% of the variability in global crude oil production. However, this pattern reverses after 2000 onwards, as fluctuations in global oil production are largely attributed to market-specific events (6%). We show that oil supply shocks may have very different effects on the real price of oil, depending on the underlying specification of the shock. In particular, the measures that capture market-driven shifts in oil supply are found to be more plausible than the rest in explaining the variability of the real price of oil, especially when compared with flow supply shocks. In fact, analysis suggests that flow supply shocks underestimate the historical contribution of oil supply shocks to changes in the real price of oil, in contrast to total supply shocks that appear to have exerted significant upward pressure in the real price of oil especially between 2003 and mid-2008. Overall, endogenous supply shocks play an increasing important role in the historical evolution of the oil price, but it must be noted that oil price developments after 2010 are largely attributed to exogenous supply shocks. We conclude that historically the supply side of the market has been an important determinant of the real price of oil after all.
Best Practices for Obtaining Representative Formation Water Samples Using Formation Testers
Authors: Kim I. , Ramaswami S. R. , den Heuvel M. Mooijer-van , Koot W. , Cornelisse P. M. , Elshahawi H.
Published: September 2016

In the increasingly complex and challenging environments that oil and gas developments have to contend with, understanding of fluid properties is essential in optimizing the concepts that are ultimately used in development. The collection and analysis of downhole hydrocarbon samples have been given top priority, with the associated uncertainties having been dealt with adequately. By contrast, early assessment of formation water properties, has not always received the same level of attention with the reduction of the associated uncertainties generally not as robust.

This paper discusses the primary water properties and their impact on field developments. We discuss why it is critical that formation water samples are truly representative of the actual in-situ formation water properties. We then examine the two biggest challenges for formation tester sampling: mud contamination and inadequate conditioning/handling of the samples, particularly in wells drilled with water based mud (WBM). Finally, a case study is presented including the use of a miscible water tracer as well as the use of focused-sampling to obtain water samples with ultra-low mud contamination to emphasize the importance of obtaining reliable decontaminated formation water properties.
Application of Multi-Well Pressure Pulse-Code Testing for 3D Model Calibration
Authors: Aslanyan A. , Aslanyan I. , Farakhova R.
Published: September 2016

The paper describes advanced inter-well pressure interference testing used for 3D model calibration accounting for formation layering and rock compressibility in a mature Siberian waterflood field.

The new interference test is based on pulse-code testing (PCT) and can scan inter-well zones without a longterm production shutdown, normally required for conventional pressure interference testing (PIT).

There are numerous applications of this technique but this paper shows only two of them: Calibration of a geological model with respect to shale breaks by determining effective formation thickness by PCT and then its correlation with a production flow profile determined by Spectral Noise Logging and temperature modellingDetermination of rock compressibility distribution throughout a 3D simulation grid by estimating formation compressibility from PCT and correlating it with formation porosity from open-hole logs

The importance of compressibility calibration cannot be overestimated because it defines the formation pressure response to the non-compensated or over-compensated withdrawals across the field and different pay zones.

Conventional PIT can assess formation transmissibility and hydraulic diffusivity between wells. These two properties can be further converted to some basic 3D model inputs, for example effective formation thickness and compressibility, if permeability, SCAL, PVT and formation saturation are known. The main limitation of the conventional PIT is that it requires a receiving well to be shut-in to avoid contamination from production and that the pressure signal should not be contaminated by interference with other wells except the selected pulsing one. This limitation makes conventional PIT impractical for quantitative reservoir characterisation.

PCT generates coded flow-rate pulses in one well and provides a mathematical technique to decode a pressure signal in receiving wells into components from each pulsing well. This allows running PCT in multiple working wells with pre-set rate variation without shutting down production and assessing several inter-well intervals in parallel. A one-month PCT described in this paper resulted in 5% production loss, while conventional PIT would need three months with 60% production loss and a high risk of failure due to pressure contamination from remote processes.
Pushing the Completion Design Envelope in Ultra-Deepwater - Design, Installation, and Performance of Deep High Pressure Completions - A Case History of the Gunflint Development, Offshore Gulf of Mexico
Authors: Sanford Jack , Healy John , Hopper Tim , Fink Josh , Grammer Ladd , Koy James , Perroux Jocelyn , Magin Ian , Williams Kevin , Seeley Tom
Published: September 2016

A Gulf of Mexico case history is presented that describes the successful delivery of two (2) deep (27,000-ft) high pressure (>17,500-psi) high rate design (25,000 BOPD) oil wells in an ultra-deep water (+6000-ft) environment. Well conditions, coupled with challenging production requirements (depletion of 10,000-psi), provided a very arduous design challenge. One well was completed as a single frac pack at 27,000-ft MD. The second well required a stacked frac pack at 25,000 ft-MD and intelligent flow controls.

Twenty-seven (27) firsts, to the industry and / or Noble, were required to deliver the final completion designs. These firsts ranged, to name a few, from a new tieback casing material, a paradigm change in the Temporary Abandonment (TA) procedure (which yielded a cost savings of $15 million per well), a new perforating charge, qualification of a new material for the Gravel Pack (GP) packer, weighted frac fluids, changes in the upper completion designs, Vacuum Insulated Tubing (VIT) welding qualification and re-design of a control line Y-block. Any one item or any single technology gap, is seldom insurmountable. However, it is the layers and the multitude of challenges in these type of environments, where every component and their interdependencies are stretched to the edge of the design envelope that pushes the completion team and suppliers to their limit. All of these together make the goal of flawless execution very challenging. This paper will provide an overview from design thru operations, and highlight some of the engineering challenges and lessons learned.

A field proven completion delivery process combined with a team of experienced people and rigorous procedures successfully designed and delivered two (2) complex completions that were on the edge of deep-water completion technology. Based on the Rushmore Review database, both wells (1 single GP and 1 single selective GP) were the fastest completions (when analyzed on a well depth basis) since Macondo. Both wells were completed in 2015, and are currently waiting on final hook-up and commissioning. First oil is forecast for July 2016.

Industry will continue to explore ultra-deep water and discover deeper and higher pressure reservoirs that push the completion technology envelope. It is imperative that engineers be able to confidently design and deliver completions for this extreme environment that will achieve the productivity and reliability required by the project economics. The aim of this case history is to provide the engineer, faced with similar challenges, with information that may prove beneficial in the approach, method, design and delivery of these type of complex, critical completions.
Petrophysical Study of UAE Carbonate Outcrop at Jabal Hafit
Authors: Sondergeld Carl H. , Wampler Jeff , Abdelghany Osman , Anin Al , Rai Chandra , Curtis Mark
Published: September 2016

Jabal Hafit consists of Tertiary outcrops that give insight into stratigraphic sequences and regional reservoirs in the Middle East. This study examines outcrops from various strata in the Rus, Dammam, and Asmari Formations varying from Early Oligocene to Eocene in age. These Formations exist throughout the UAE and Middle East and contain some large regional hydrocarbon reservoirs.

This study examines porosity, permeability, mineralogy, NMR, MICP (mercury injection capillary pressure), and SEM images for 72 core samples. FTIR (Fourier Transform Infrared) mineralogy shows that these samples are calcite dominated carbonates with two strata being dolomite dominated. Sample porosities decrease linearly with increasing pressure and range from 0.47 to 27.26%. Klinkenberg permeabilities decrease linearly with increasing pressure for most samples, with some samples showing nonlinear pressure dependence indicating the presence of cracks. Permeabilities range from 0.0002 to 54.85 md. A porosity-permeability correlation has been developed based on measured core data. The Reservoir Quality Index is used to identify similar reservoir flow characteristics and two flow zones have been identified across the three Formations. The second flow zone demonstrates some permeability pressure dependence. NMR shows bimodal pore distributions in some samples as well as extreme variability from layer to layer. A comparison of NMR, ϕNMR, and Boyle's Law, ϕHe, porosities shows good agreement at porosity values lower than 10% with the ϕNMR < ϕHe at larger porosities. The Free Fluid Model and Mean T2 Model are used to estimate permeability from NMR data. Corrected T2 cutoffs are determined from Swir via centrifuge method to define the correct Bound Volume Irreducible (BVI) and Free Fluid Index (FFI) for each sample. Measured T2 cutoff times range from 2.38 to 598 ms. Calibrated and uncalibrated Free Fluid Model and Mean T2 Model permeabilities are compared with measured core permeability values. For these samples, the Mean T2 Model gives a better permeability estimate. SEM images reveal the bulk of the pores are equant in shape and document the existence of microporosity. Some MICP and NMR measurement capture the bimodal pore distributions.
Experimental Study of Gas-Liquid-Coal Fines Three-Phase Flow in Undulating Horizontal Wellbore
Authors: Han Guoqing , Pan Zhejun , Zhang He , Ling Kegang , Teodoriu Catalin
Published: September 2016

In Coalbed Methane (CBM) reservoir, especially the thin low permeability CBM reservoirs, undulating horizontal wells are often drilled to maximize contact area with the reservoir for higher CBM production rates. Coal fines, however, may accumulate in the wellbore, making pressure along the wellbore trajectory more complex, affecting gas production behavior. This paper presents experimental work to study the coal fines-water-gas three-phase flow in transparent pipes to mimic different undulation angles that may occur in horizontal wells. Coal fines with different particle sizes are studied. Observed from the experiments, four flow patterns for coal fines migration were identified: stratification, saltation, moving dunes, and dispersed flow. Moreover, relations between coal fines critical moving velocity and discharge velocity and the size of coal fines are investigated. This paper further investigated the settlement and plugging of coal fines at the curvature section of the pipes under four flow regimes: elongated bubble, transition, slug, and intermittent flows. Using the experimental data, we estimated the boundaries for five flow regimes under five different undulation angles. The analyses indicated that the pressure fluctuation magnitude increases when flow regime evolves from bubble flow to intermittent flow. The largest pressure fluctuation and the lowest fluctuation frequency take place under intermittent flow. Based on the experimental data, this paper derived the critical velocity correlation for coal fines in undulating CBM wellbore. The findings of this study is useful for CBM development in the field, which may help to optimize wellbore geometry to minimize coal fine settlement/plugging, act as a guide in designing well flushing operation to effectively circulate coal fines out of bottomhole.
Selection of Geologic Models Based on Pareto-Optimality Using Surface Deformation and CO2 Injection Data for the in Salah Gas Sequestration Project
Authors: Min Baehyun , Nwachukwu Azor , Srinivasan Sanjay , Wheeler Mary F.
Published: September 2016

A model selection process based on multi-objective optimization using a fast proxy is presented that chooses geologic models conditioned to observed flow and geomechanical responses. The responses of geologic models to injection of large volumes of CO2 are evaluated using a proxy that approximates pressure distribution using a random walk particle tracking algorithm and computes surface deformation using a stress-field solver. The geologic models showing similar proxy responses are grouped into clusters by invoking multi-dimensional scaling and k-means clustering. A representative model of each cluster is chosen and its simulation results are compared to the observation. The resultant posterior ensemble consists of models that belong to one or more clusters whose representative models are not only in good agreement with given observation data but also non-dominated to other representative models. The usefulness of the model selection approach is demonstrated on CO2 sequestration of a fractured gas reservoir at In Salah, Central Algeria. The explicit coupling of the connectivity estimator and the stress solver reproduces similar migration patterns of CO2 plume to those obtained using full-physics numerical simulations. Incorporating time-lapse observations measured using satellite-based interferometric synthetic aperture radar imposes additional constraints to refine geologic models by improving the matching quality of bottomhole pressure, and thereby contributes to a further reduction in geologic uncertainty. The multi-objective optimization process implemented in the model selection process yields a diversified model set than those obtained using a global optimization procedure. The posterior ensemble exhibits consistent geologic characteristics in terms of spatial distribution and orientation of migration pathways. The posterior ensemble is then used as an initial population for a multi-objective history matching procedure. The results of model selection and expansion process indicate that the implementation of Pareto-optimality is advantageous to realize diversified geologic models that yield unbiased assessment of uncertainty associated with prediction of future CO2 plume migration.
Quantification of Directional Pore Network Connectivity and Rock Fabric and its Application in Enhanced Assessment of Hydrocarbon Reserves
Authors: Garcia Artur Posenato , Heidari Zoya
Published: September 2016

Success of the strategies to exploit hydrocarbon reservoirs depends on the availability of reliable information about pore structure and spatial distribution of fluids within the pore network. Reliable quantification of directional pore network connectivity and characterization of pore architecture is, however, challenging. The objectives of this paper include (a) quantifying the directional connectivity of pore network and rock components, (b) investigating the consistency of the estimated directional connectivity at a given rock type in the formation, (c) identifying geometry-defined fabric features that cause the connectivity variations within the same formation, and (d) improving assessment of hydrocarbon saturation using the introduced quantitative directional pore-network connectivity factor.

We introduce a new directional pore-network connectivity factor to quantify rock fabric. In order to evaluate its consistency in pore- and log-scale domains in the same rock types, the first step includes rock classification based on well logs and well-log-based estimates of petrophysical/compositional properties. Then rock samples from each rock type are scanned using a micro-Computed Tomography (CT) scanner, processed, and digitized into pore and grain regions. Afterwards, the pore-network connectivity of the three-dimensional (3D) pore-scale images are obtained using a semianalytical streamline algorithm. The geometrical features are quantitatively evaluated from these images and combined with the estimated connectivity. The new quantitative connectivity factor is finally used to improve evaluation of electrical resistivity logs for assessment of hydrocarbon saturation.

We successfully applied the introduced method to a carbonate formation. The results confirmed that the introduced directional connectivity factor can detect rock fabric features and is a function of the directional diffusivity coefficient. This parameter remains persistent in the same rock type in the formation, which enables a reliable and enhanced interpretation of electrical resistivity logs in formations with complex pore structure. The quantification of rock fabric and pore network connectivity improved the estimation of hydrocarbon saturation by up to 61% when compared to conventional methods. The use of such parameter for rock fabric characterization minimizes the need for calibration efforts in interpretation of borehole geophysical measurements. Few cuttings from different rock types are sufficient for the proposed method.
Describing and Modeling Saturation Versus Height in Fields With Immobile Hydrocarbons Below the Contact
Authors: Pentland Christopher H. , Yarabi Mohamed K. , Boya Ferrero Maria J. , Svec Robert K.
Published: September 2016

We investigate the relationship between saturation and height in fields where oil or gas is present below current day free water level. Such situations arise in a number of fields in Oman with complex charge, structural and regional hydrodynamic history. The change in saturation with height – and importantly whether intervals contain mobile or immobile hydrocarbons – is a key parameter influencing volumetrics and field performance.

The correct identification and interpretation of this phenomenon is hindered by the inability to reconcile core-based saturation-height relationships with field observations including saturation from logs. This difficulty arises as core-based saturation-height modeling traditionally only considers the primary drainage (hydrocarbon displacing water) flow sequence. We present a simple analytical model incorporating both core-based primary drainage and imbibition (water displacing hydrocarbon) flow sequences which is able to describe the complex saturation scenarios discussed. The model has been validated against numerical simulations, can handle multiple rock types and is easily coded in a spreadsheet.

We compare our simple core-based model with log observations from example fields. The model can replicate observed saturation profiles within measurement uncertainty including the mobile hydrocarbon saturation above the current free water level as well as the immobile hydrocarbon saturation below. The implications for correct log and core data gathering and interpretation are summarized and the impact on field performance is discussed.

The work highlights the important role the imbibition flow sequence can play in describing hydrocarbon saturation changes with height in some fields: this is often overlooked yet critical for the correct description of some fields. Model inputs require imbibition experiments to be considered in data gathering campaigns.

A companion paper published in parallel discusses the processes that affect fluid distributions and outlines recommended diagnostic tools and workflows (Boya Ferrero et al., 2016).
Reservoir Characterization Using Fuzzy Kriging and Deep Learning Neural Networks
Authors: Korjani M. M. , Popa A. S. , Grijalva E. , Cassidy S. , Ershaghi I.
Published: September 2016

The sandy-clayed heavy oil hydrocarbon reservoirs of the Miocene formations in San Joaquin Valley, California, present relatively high complex geologic settings. These reservoirs consist in general of sandstone, silts and shale bodies, and present anywhere from six to eight degrees of inclination. Geostatistical tools were used to characterize the reservoir and develop a full earth model for the field. The data used was mainly based on the suite of resistivity logs (shallow, medium and deep), which seems to best represent the formations, while a classic kriging technique was used for modeling.

In the present research, we introduce a new approach for characterization of these heavy-oil reservoirs by using fuzzy kriging and deep learning neural networks. The new model better captures the uncertainty associated with the characteristics of the reservoirs. Once successfully trained, the system was applied to generate a 3D earth model and estimate reservoir properties at any point in the field. The new earth model successfully improves the resolution and realization of the subsurface model, as compared to the existing one developed using classic kriging. Integrating fuzzy kriging solves the limitation of smoothness of kriging estimation and reproduction of extreme values. Additional capability includes generation of synthetic logs for wells anywhere in the reservoir, with a significant application for infill drilling.

The methodology presented in this research proved to be very successful as developed for modeling alluvial deposits such as the heavy oil reservoirs in San Joaquin Valley, California. Further research should be considered to address other geologies where laterally formations vary in characteristics or where pinch outs or faulting occur.
Solids Production Prediction and Management for Oil Producers in Highly Depleted Reservoirs in a Mature Malaysian Field
Authors: Asadi M. S. , Khaksar A. , Ring M. J. , Saric D. , Yin Yin M.
Published: September 2016

This paper presents a case study of a geomechanical evaluation used in sand management decisions in a mature oil field offshore Malaysia. Elements of a field-wide geomechanical model were constrained from various data types from a vast number of wells drilled in 1980s and new re-development wells drilled in 2013–15. Extensive production from multilayer stacked reservoirs has resulted in large pressure depletion; hence drilling of infill wells and water injection is used to enhance oil production in the field.

A poroelastic analytical sand production prediction approach was used to investigate the risk of sanding in both existing and new wells under high depletion conditions. Historical production data were used to calibrate and verify the sand production predictions. The analysis also included rock mechanics laboratory experiments on core samples saturated with mineral oil and brine to characterize the amount of rock weakening in the presence of water, which showed target sandstones may weaken by 13–16% when they are exposed to brine compared to the mineral oil saturated condition.

The results showed a very low risk of sanding for the target oil reservoirs over the field life, using expected final reservoir pressures of 100 psi for cased and perforated completions drilled in any direction. The risk of sanding for open holes, however, was found to be slightly higher with further depletion from the current reservoir pressures, particularly with the likely rock weakening effect under water production and injection conditions. Moreover, hole instability and solids production resulting from the failure of the shale interbeds under low downhole pressures and water production could be a well integrity risk, jeopardizing production in open hole completions.

The sand production prediction model is used to identify the optimum completion strategy in new wells considering the strength of target reservoir rock, well trajectory, and reservoir pressure and production conditions on a well by well basis. For most planned wells, cased hole completions with oriented and selective perforations appeared adequate to mitigate the sanding risks in both production wells and water injectors. Sand-free production to date from recently-drilled cased and perforated infill wells confirms the accuracy of the pre-drill sanding evaluation and sand management decisions.
Reuse of Produced Water by Membranes for Enhanced Oil Recovery
Authors: Nair Remya Ravindran , Protasova Evgenia , Bilstad Torleiv , Strand Skule
Published: September 2016

Produced water (PW) management and reuse of PW has economic and environmental benefits compared to PW discharge. This research focuses on membrane separation efficiencies in adjusting the ionic composition of de-oiled PW and evaluating the possibility for smart water production from PW for enhanced oil recovery. Key characteristics of smart water for carbonate reservoir is increased concentration of divalent ions and depletion of monovalent ions.

Dual media is used for oil removal from PW. De-oiled PW is feed for Nanofiltration (NF) membranes for separation of barium and calcium ions. Combination of NF retentate with seawater (SW) as feed and NF permeate from PW is also considered. PW permeate is mixed with SW spiked with determining multivalent ions, sulfate or phosphate, which alter wettability of oil reservoirs.

Currently, smart water is produced by adding chemicals to fresh water or low total dissolved solids (TDS) water produced by reverse osmosis (RO) or flash distillation. Using de-oiled PW as feed to NF will reduce power consumption, footprint and chemicals. PW can be reinjected into reservoirs after removing scale-causing ions. By injecting low barium and calcium PW brines, the frequency of scale squeezes will decrease. Membrane performance is evaluated for flux and separation efficiencies of calcium and barium. Barium concentrations in synthetic PW is increased 20 times the original concentration in Tor Field in North Sea, for evaluating NF separation efficiency. Negligible amount of barium is present in NF permeate at pressures of 8-12 bars resulting in a permeate flow rate of 200 L/h for a membrane area of 2.6 m2.

Increased sulfate concentration in smart water enhances recovery by 40 % of original oil in place. However, BaSO4 scalingcan be initiated even with negligible barium concentration if high sulfate level is present in the injected brine. The novelty of this research resides in the use of non-precipitating phosphate replacing sulfate for smart water production, simultaneously decreasing barium concentration and scaling potential of PW. However, precipitation of calcium occurred in presence of high concentration of phosphate. Power consumed by NF membranes for smart water production is calculated at 0.37 kWh/m3.
Increase Efficiency of Smart Field Integrated Operations Through Service Level Management
Authors: Reddicharla Nagaraju , Bangari Praveen , Konkati Sarath
Published: September 2016

The current trend of low oil and gas prices demands operators to improve operational effectiveness and optimize production at different process cycles range from days to months to years. Smart field integrated operations plays a major role and provides more rigorous, effective and consistent surveillance to help reduce deferment, accelerate decision making and enhance production system performance. This paper talks about how the efficiency of smart field operations can be improved by enabling service level management for the data, processes and IT applications.

In general smart field operations are often failed due to lack of knowledge to turn the data into meaningful information especially in the case of real time surveillance activities for a given business critical challenge to make an operational advise & decision and the complete sense of asset awareness translating into asset optimization. Smart fields is not just about improved automation.

The first step in this new approach is to create a service catalog (such as Water injection surveillance, ESP & Gas-lift surveillance, well & facility reviews…etc.) for identified business challenges (High GOR, High water cut, process debottle-necking…etc.) in the asset where the smart field integrated operations can provide solutions. After the business process is identified for a given service, the second step is to augment the processes with the depth of service requirements and define the service execution workflow by enabling smart field integrated operations in it. The third step is to define the staffing or resource model to deliver the service in the asset. The existing resources in the asset can also carry out certain jobs in the service execution. The fourth step is to derive the tangible and intangible value generated from the service delivered and aligned to organizational KPIs. The fifth and final step is to capture the knowledge generated from the services for the future use.

The real time data availability at the right time with the given frequencies, business process performance at the agreed service levels in the service execution workflow and the availability of IT applications play a major role to achieve the success. However this can only be efficiently monitored with the agreed service levels defined into it and tracked for continuous improvement. The assets teams can meet on a scheduled basis and review the performance of services delivered and measure efficiency of smart field integrated operations.

This helps to eliminate waste and improve productivity and use the asset resources efficiently with the help of smart field integrated operations. This paper illustrates the detailed approach, application of services levels in the processes, examples and the benefits.
Oil Viscosity Estimation from NMR Logs for In-Situ Heavy Oil Characterization
Authors: Hursan Gabor , Seifert Douglas J. , Lyngra Stig , Palmer Richard G.
Published: September 2016

This publication presents the calibration of a downhole nuclear magnetic resonance (NMR) log-based oil viscosity correlation with laboratory live oil viscosity measurements. The laboratory data set was acquired from formation tester sampling (FTS) including 37 pressurized single-phase oil samples taken from 11 wells. The FTS oil viscosity range was 1-1,400 centiPoise (cP).

In two Saudi Arabian carbonate fields, the moveable hydrocarbons consists of crude with in-situ oil viscosities of ~1-3 cP. Thick tar mats are located below the oil columns, separating the moveable hydrocarbons from the aquifers. For pressure support, horizontal water injectors are drilled into the heavy oil transition zones, located between the moveable oil and the tar, utilizing real-time logging while drilling (LWD) NMR data and formation tester mobility data for well placement. For optimum water injector placement, accurate NMR log-based determination of the reservoir oil viscosity is critical. The NMR logs are processed using an integrated petrophysical model that subdivides the oil volume into light, medium and heavy components. The in-situ viscosities are calibrated to the relative percentage of heavy-medium components to the total oil volume.

Despite the large geographic distance between the 11 sampled wells, the presented results reveal a remarkable consistency between the in-situ oil viscosity data from the FTS laboratory analyses and the NMR log responses. In this particular case, the well results suggest that one viscosity relationship is adequate for describing a large geographical area containing multiple medium and heavy oil reservoirs. The results indicate the logarithm of viscosity to be a clear function of the heavy-medium oil volume percentage. Two distinct linear segments are sufficient to cover the full 1-1,400 cP oil viscosity range. One of these segment describes the mobile oil column with low heavy-medium oil volume percentage and oil sample viscosity of less than 3 cP. The other segment defines the oil/tar transition zone where the presence of asphaltene aggregate structures leads to a very rapid increase of oil viscosity versus depth covering the range 3-1,400 cP. The robustness of the method is demonstrated by the low statistical uncertainties for the entire viscosity range, when comparing the predicted NMR oil viscosity correlation results with the laboratory results, from the 37 physical oil samples.

The new NMR empirical oil viscosity correlation was built on a previously published methodology, but the existing correlation did not do a particularly good job for the lower oil viscosity range (<10 cP) and for the very heavy oils. The purpose of this new publication is to present a new empirical NMR viscosity correlation with much wider validity range.
Uncertainty Quantification for History Matching Problems With Multiple Best Matches Using a Distributed Gauss-Newton Method
Authors: Gao Guohua , Vink Jeroen C. , Chen Chaohui , Tarrahi Mohammadali , El Khamra Yaakoub
Published: September 2016

It is crucially important for decision making and an extremely challenging task to properly quantify uncertainty of model parameters and production forecasts after conditioning to production data. A novel approach is proposed to generate approximate conditional realizations using the distributed Gauss-Newton (DGN) method together with a multiple local Gaussian approximation technique. Results are compared with those obtained from other approaches such as Randomized Maximum Likelihood (RML), Ensemble-Kalman-Filter (EnKF), and Markov-Chain-Monte-Carlo (MCMC) simulation.

The DGN method is developed to find multiple local minima of the objective function in parallel, by collecting and sharing information from dispersed regions in parameter space dynamically. Around each local minimum, the estimated Hessian obtained from the Gauss-Newton approximation along with the prior inverse covariance matrix is used as a local approximation of the posterior inverse covariance matrix. The posterior joint PDF can then be approximated as a weighted linear superposition of multiple local Gaussian distributions, which can be sampled very efficiently without having to resort to expensive MCMC methods.

The proposed approach is first validated using a nonlinear history matching toy problem with multiple modes. In terms of efficiency, the new approach can significantly reduce the computational cost and accelerate the uncertainty quantification process, when compared to the traditional RML method or traditional MCMC approaches. In terms of accuracy, uncertainty characteristics obtained from the proposed approach are comparable to those generated from the MCMC simulation, and they are much better than those obtained from EnKF or RML. The approach is then also applied to a real field history matching problem, where the dynamic system of multi-phase flow in the reservoir exhibits very strong nonlinear behavior, and the objective function has multiple local minima. Uncertainty ranges of production forecasts for the real field case are quantified by generating an ensemble of conditional realizations. The production forecasts for all conditional realizations are consistent with the production data observed after the history matching period, which further validates the applicability of the proposed method to real field problems.

Its high efficiency makes the new approach practical for large-scale problems, for which methods based on Design of Experiment break down. Furthermore, as was argued by Vink, Gao, and Chen (2016), inevitable under-modeling reduces the urgency of using very accurate methods to quantify uncertainty, and using a multi-Gaussian approximation of the posterior should be more than sufficient. The proposed approach has been implemented in our next generation reservoir simulation and history matching system called PetroSigns.