bluuebunny/crossref_metadata_2025 huggingface dataset:
Well Integrity Risk Mitigation vis-a-vis Revenue Potential: A Qualitative Model for Wellwork Prioritisation in Dukhan Field, Qatar
Authors: Singh Sanjay K. , Negron Jose , Al-Marri Nasser , Arijo Nasir Murtaza
Published: March 2015

Qatar Petroleum's supergiant Dukhan field located onshore Qatar has a mature well inventory of hundreds of wells. Mitigating well integrity risk without affecting crude oil production and water injection targets is critical to sustaining revenue streams from the field. This involves a large number of integrity repair wellwork with workover rigs. Performing such a wellwork campaign is time-intensive and without adequate prioritization has the potential of jeopardizing well integrity and causing safety/environmental issues besides adversely affecting the production and injection levels. This paper discusses a qualitative model that has been developed and used to prioritize repair wellwork in Dukhan field. The model is centered round integrity risk level and revenue potential of wells. A set of integrity parameters including status of surface and downhole barriers determines integrity risk level. Another set of reservoir management and well capability parameters determines revenue potential. Each of the wells is then assigned scores to reflect the risk level and the revenue potential. Cross-scaling of such scores defines the priority of a repair wellwork. Using the above approach for wellwork prioritization has been effective in mitigating integrity risk and maintaining revenue potential of the large inventory of mature wells.
The First Land Full Azimuth Seismic for Fractured-Cavernous Carbonate Reservoirs Exploration in Tarim Basin, Western China
Authors: Liu Yimou , Liang Xianghao , Zhou Yi , Liu Shiyong , Lin Shangwen , Wang Naijian
Published: March 2015

Ordovician carbonate reservoirs are the very important yet difficult targets in the oil and gas exploration and development of Tarim basin, western China. The main task (also main challenge) of seismic is to image and predict the storage spaces of carbonate reservoirs-the secondary dissolved caves, holes and fractures, which are buried in more than 6500m deep. The target formations are usually in very low signal-to-noise ratio due to the seismic attenuation and the caves and fractures are small and aligned in random directions. Narrow azimuth and conventional wide azimuth seismic fail to image and identify the fractured-cavernous reservoirs accurately, leading to many drilling failures. Here, the effects of some key acquisition parameters such as bin size, fold and aspect ratio on carbonate reservoirs imaging accuracy are carefully examined using seismic forward modeling and new analysis methods. A high-density full-azimuth seismic acquisition was carried out based on the above analysis and the results show that small bin size has the advantage to imaging the ultra-deep carbonate reservoirs and the fracture prediction results from full azimuth data well agree with that from imaging well logging data. A set of well drillings based on the full azimuth data have been proved to be successful.
Reliable Fracture Characterisation and Value Addition Through Special Core Reorientation: Kuwait Case Study
Authors: Alenezi A.M. , Narhari S.R. , Al-Ajmi N.H. , Pattnaik C. , Rao J.D. , Al-Ateeqi K.A. , Staffelbach C. , Anis Abdel-Hamid Anis , Chakravorty S. , Barbe J.F.
Published: March 2015

Reliable fracture characterization is essential for efficient field development of tight carbonate reservoirs. A comprehensive campaign of core based fracture analysis was carried out on more than 7,000ft of deep tight carbonate (over 14500ft TVD and 3pu avg. porosity and 0.1 mD avg. perm) cores of Kuwait, spread over a number of wells covering a large area of over 1000sq km.

The aim of the study was to provide inputs for a detailed structural analysis of the area, with the help of reorientation of cores focusing on the geometrical and structural characteristics of each well. The reorientation procedure used a special core Goniometry process, which permits a totally hands-free 3D digitization of all planar and linear features. Reorientation of the cores is established using either the deviation data from the wells or through comparison with image log data.

In addition to the detailed integrated description of type, size, aperture and filling of fractures, a porosity/permeability model was generated after calculation of fracture frequency. By calculating the orientation and value of the permeability vectors, an indication of optimum direction of drilling was established for each well/area.

The natural fracture network obtained with open, partially-open and cemented fractures, together with induced stress-release fractures analysis, contributed to a better understanding of tectonic history and present-day stress in the studied area. A field synthesis map highlighted the main direction of all types of fractures and an actual stress map was worked out by compiling all directions of the maximum horizontal stress observed in the wells and oriented by the petal and centreline induced fractures.

The integration of the results with analyses of image log data, well log correlation data and seismic data provided critical information about the reservoir properties.
A Type Curve for Carbonates Rock Typing
Authors: Wibowo A.S. , Permadi P.
Published: March 2015

Rock typing for heterogeneous carbonates is still a standing problem. The present work was directed to investigating the relationship between microscopic geological characteristics of carbonates and architecture of the pore systems in the effort to develop a better method for carbonates rock typing. Eight carbonate reservoirs with complete core analysis data of 1,838 core plugs were used in this work. Six carbonate data sets were utilized in developing the method and the rest two were used for verification.

The well known Kozeny's equation was employed to provide the relationship between pore geometry and the structure. It can be shown that these pore attributes contain only permeability and porosity. A comprehensive analysis was then carried out by plotting pore geometry against pore structure on log-log graphs (PGS cross-plot) and identifying microscopic geological features of every core plug employed. Results for each carbonate data set show that the data points divides into six to thirteen clusters, each cluster has its own similarity in the microscopic geological features, the fitting line drawn on each cluster has very high correlation coefficient, the space between two closest fitting lines is all practically the same, and interestingly all the fitting lines tend to converge to a single point. A mathematical analysis done confirms the existence of this point, leading to the construction of a type curve. The rest two carbonate data sets perfectly verify this type curve.

This work differs from the previous ones in that the present work honors both geological and engineering aspects equally and reveals that certain diagenetic processes have produced certain pore architecture as exhibited on the PGS plot. This paper overall provides a better understanding about rock type definition, a tool to identify the effects of diagenetic processes on rock properties, and a type curve for easy rock typing.
Unlocking the Potential of Complex Marginal Reservoir in Highly Mature Oil Field, XiJiang24 South China Sea
Authors: Donghong Luo , Zhenghe Yan , Xiaofei Gao , Zhihua Rao , Yu Du Ding , Halomoan Parlindungan Monris , Bisain Amarjit Singh , Yang Liu , Azwar Olivia
Published: March 2015

An oil & gas operator in XiJiang block offshore South China has shifted the development of highly mature oil fields that have been producing for 17 years toward the remaining undeveloped marginal reservoirs using a horizontal well drilling program.

The main targets of the new development campaign are the remaining thin oil column reserve in attic locations of the reservoirs as well as the unproduced thin laminated reservoirs in the area. Upon understanding the uncertainties and challenges associated with drilling horizontal wells in these complex reservoirs, an innovative drilling approach was initiated for accurate horizontal placement in thin sands, channel sands, and thin oil column reservoirs with strong bottom-water. The approach includes the integration of an advance multifunction formation evaluation Logging-While-Drilling (LWD) tool that provides real-time formation evaluation and structural interpretation along with a bed boundary mapper LWD tool with the ability to map multiple key boundaries that are the prerequisite parameters that must be identified during the execution stage and which include the water contact and top and bottom of the reservoir structure simultaneously in distance.

Outstanding outcomes have been observed by implementing this new approach in the complex target reservoirs. The approach was applied to multiple challenging wells, each of which has produced from 2,000 to 6,000 BOPD with very low water cut, far exceeding the set production goals of 1,500 to 2,000 BOPD. These are very promising development economics in the oil fields that have 90% to 95% water cut on average.

The successful implementation of the new development strategy in highly mature oil fields will lead to sustained and extended production, increasing the ultimate recovery and well economics. The approach provides an example of using integrated technology solutions to overcome the challenges in complex target reservoirs.
Non-Hyperbolic Moveout Multi-Parameter Anisotropic Tomography
Authors: Panizzardi J. , Bienati N. , Gentile E.
Published: March 2015

Application of anisotropy has proved to be mandatory for the improvement of imaging quality, at the point that nowadays the introduction of TTI anisotropy has become a standard for PSDM projects. These advancements pose new challenges to migration velocity analysis, and the time domain approaches commonly used for the estimation of anisotropic velocity parameters are no longer enough to satisfy imaging accuracy requirements.

A depth-domain estimation technique is proposed, which is completely based on PSDM and on the classic CIG (Common Image Gather) flattening principle.

One of the key aspects is the use of a robust automatic non-hyperbolic moveout picking algorithm, which is applied on the depth migrated CIGs and provides the correct description of the complete residual moveout: this allows the joint tomographic inversion of two anisotropic velocity volumes, which are able to properly account for the non-hyperbolic residual moveout behavior at both short and long offsets. The method has general validity and it can be applied to any imaging project; it is also particularly stable when applied to multi-azimuth acquisitions.

This approach can obtain a good anisotropic focusing velocity if the data contains sufficiently large offsets, although still one or more wells are needed to constrain vertical velocity.
Seismic Attributes and Advanced Computer Algorithm Method to Predict Formation Pore Pressure: Paleozoic Sediments of Northwest Saudi Arabia
Authors: Nour Abdoulshakour , AlBinHassan Nasher
Published: March 2015

Oil and gas exploration professionals have long recognized the importance of predicting pore pressure before drilling wells. Pre-drill pore pressure estimation not only helps with drilling wells safely but also aids in the determination of formation fluids migration and seal integrity. With respect to hydrocarbon reservoirs, the appropriate drilling mud weight is directly related to the estimated pore pressure in the formation. If the mud weight is lower than the formation pressure, a blowout may occur and, conversely, if it is higher than the formation pressure, the formation may suffer irreparable damage due to the invasion of drilling fluids into the formation. A simple definition of pore pressure is the pressure of the pore space fluids in excess of the hydrostatic pressure. The cause of abnormal pore pressure includes quick burial of unconsolidated sediments before dewatering, hydrocarbon formation in the pore space of rocks, mineralization such as smectite-illite osmosis, tectonic movement of sediments and other geological processes that result in overpressure.

Geoscientists and engineers have used various techniques to predict abnormally high formation pore pressure from seismic data. These techniques primarily employ the empirical relationship between seismic velocities and formation density. Consequently, many investigators have shown the sensitivity of seismic velocities to other factors such as lithology, gas and pore fluid content, which reduces the reliability of purely velocity-based methods in predicting abnormally high formation pressure (Young and Lepley, 2005). In this study we will focus on using an advanced pattern recognition computer algorithm, called Support Vector Machine (SVM) and attribute data from seismic and wells to the prediction of formation pore pressure in the lower Paleozoic Qalibah formation of northwest Saudi Arabia.
Deepwater Production Improvement Through Proactive Reservoir Management and Conformance Control
Authors: Masoudi Rahim , Karkooti Hooman , Jalan Shlok , Arif Anndy , Chan Keng S. , Othman Mohamad B. , Burford Steve , Bee Philip
Published: March 2015

Deep water fields are commonly subject to high development cost, challenging topside and subsurface issues and uncertainties. The level of heterogeneity, compartmentalization, fault intensity, reservoir connectivity, pressure and flow communication across the field, sand/fine production, wellbore stability are commonly less well understood at the time the development decision is made. The reservoirs may also consist of very thin beds to thick blocky sands and the reservoir properties can vary significantly both laterally and vertically throughout the field.

Pressure maintenance and water/gas injection can be part of the selected development strategies from day one. Due to the high uncertainties and development cost, both producers and injectors might be pragmatically commingled across various reservoirs with no additional sandface control and operational flexibility. Reservoir management strategies may rely on field/reservoir level voidage replacement ratio (VRR) control with no additional selectivity and control on water/gas injection. This strategy combined with the above mentioned uncertainty issues can potentially lead to injection conformance issues and reduced recovery factor due to sub-optimal sweep efficiency at the sand by sand levels. A deep water example has been studied in this work showing the conformance issue and uneven pressure distribution confirmed by different PLT campaigns and MDT pressure surveys for various reservoirs under VRR control.

In this paper, the above challenges and reservoir management (RMP) requirements combined with the concerns of the optimized water flooding in a complex deep water field in Malaysia have been studied and discussed. The application of the proposed guidelines and strategies for proactive reservoir management and conformance control showed potential for significant improvement in sweep efficiency optimization and hydrocarbon recovery improvement in this deep water field.
Sampling While-Drilling Goes Where Wireline Can't: Case Studies Illustrating Wireline Quality Measurements in Challenging Borehole Environments.
Authors: Sanchez Francisco Galvan
Published: March 2015

In the early 2000s, formation pressure while-drilling tools were introduced that can obtain formation pressure data, even in highly deviated wells and extended-reach drilling. In the past two years this LWD technology has evolved with the addition of downhole fluid sampling and fluid analysis. LWD Sampling and Testing can now be performed in challenging environments that cannot be performed with wireline tools such as horizontal or highly deviated wells. The limitations of wireline deployment in these wells are due to the cumulative frictional resistance of the wireline, the toolstring components and the borehole where it is run. Although several technologies exist to mitigate the risks, such as fly wheels, wireline tractors or pipe-conveyed options, operators prefer to eliminate the risks and costs associated with them by utilizing LWD technology.

The first part of this paper describes the new sampling and testing service that was designed for the LWD environment. This service has several closed-loop control systems for pressure testing, mobility determination and for pumping during the sampling and cleanup operations. In-situ fluid analysis is achieved with the use of sensors that measure optical refractive index, sound speed, density and viscosity. Downhole fluid samples are retrieved with the use of single-phase tank technology.

The second part of this paper details case studies of field tests that were performed for a major operator in Trinidad and for an IOC in the Netherlands. In Trinidad the service successfully performed pressure testing, real time fluid analysis and recovered three single phase samples while drilling a 300ft section at 70° deviation. On a dedicated logging run in the Netherlands the service first accurately took 25 formation pressure points and clearly identified three distinct gradients. The customer targeted four zones of interest and acquired 11 samples, six single phase samples in the oil zone, three single phase samples in the water zone and finally three single phase samples in the gas zone. This pressure testing and sampling operation was all executed in a 1307 m tangent section at 73° inclination. The service was utilized to determine the presence of moveable fluids in the reservoir for a horizontal development well for a customer in Norway. The tool was positioned at a sampling station with a mobility of 1.8 mD/cP and after almost 5 hours of pumpout at that station, it successfully acquired the first sample, after another 4 hours of pumpout at the same station the tool acquired the second sample.

In both cases the LWD sampling and testing service was chosen over wireline to mitigate the risks of sticking during the sampling and pressure testing operation. These field tests demonstrated that the LWD service is capable of taking wireline-quality measurements in extremely challenging borehole environments.
Deepwater Reservoir Characterisation Using Tidal Signal Extracted from Permanent Downhole Pressure Gauge
Authors: Wu Xingru , Ling Kegang , Liu Dexin
Published: March 2015

Permanent Downhole Gauge (DHG) technology has been widely used in deep water reservoir development in the last decade and is playing an increasingly significant role in real time reservoir/well surveillance and reservoir management. Tidal signal extracted from the highly accurate and precise device can be used for reservoir characterization such as monitoring the changes of saturations and estimating rock pore compressibility. Most previous works treated tidal signal as pressure "noise" and little has been discussed on how to utilize the tidal information in reservoir characterization.

This paper will address how to use Fast Fourier Transform (FFT) to extract the tidal signal and the theory and method to process the signal for reservoir characterization purposes. In addition, several examples from some deep water fields will be discussed to illustrate how to use tidal information to estimate pore compressibility, monitor dynamic fluid saturation change, and detect the presence of secondary gas cap. This paper will show that FFT is a fast and reliable method to process the DHG pressure data for tidal signal which can be used for reservoir characterization in multiple dimensions. Furthermore, the results (pore compressibility and saturation) obtained from the tidal signal are very unique because they cannot obtained in laboratory, simulation, or direct measurements because of the scale impacted by tides.
Strategies of Land Internal Multiple Elimination Based on Inverse Scattering Series
Authors: Kelamis Panos G. , Luo Yi , Weglein Arthur B.
Published: March 2015

In spite of a plethora of novel innovative algorithms for multiple identification and elimination, the fact is that their applicability and success is in most cases questionable and limited to marine environments especially deep waters. In land seismic datasets however, a clear understanding of internal multiples and their generation is not readily available and thus efforts to attenuate them become cumbersome and quite often ineffective. Particularly in desert terrains with a complex near surface and low-relief structures, surface multiples are rare. In most cases, we are dealing with so called "near surface related multiples". These are basically internal multiples generated within the complex structure of the near surface. They exhibit little moveout discrimination with respect to primary reflections and thus cannot be removed with conventional technologies commonly based on Radon transforms. Their proper estimation and subsequent elimination requires a rigorous approach firmly rooted to wave equation concepts.

In this paper we employ theoretical principles of Inverse Scattering Series (ISS) and develop distinct, cost-effective, practical methodologies for internal multiple elimination applicable for land and shallow water seismic data. These fully-automated, data-driven algorithms require no picking of events and identification of multiple generators, assume no subsurface velocity information and can be applied pre and/or post-stack. They can accommodate the broadest set of internal multiples of all orders and can be extended to multi-dimensional earth models. Thus, multiples are surgically removed by predicting their amplitudes and phases and do not harm primary reflections, even if they are proximal and overlapping. A series of realistic synthetics and field land datasets from the Arabian Peninsula are used in order to demonstrate the effectiveness of ISS-based algorithms towards the attenuation of internal multiples.
Effects of Deviated Wellbore Stresses on Compressional Headwaves and Modal Dispersions
Authors: Sinha Bikash K. , Lei Ting
Published: March 2015

A new 3D finite-difference time domain formulation of equations of motion for elastic waves in prestressed formations has been used to calculate synthetic waveforms at an array of receivers in a liquid-filled deviated borehole. These equations describe the influence of borehole hydrostatic pressure as well as triaxial formation stresses on elastic waves produced by either a monopole or dipole transmitter placed on the borehole axis. The synthetic waveforms are processed by a slowness-time coherence algorithm and modified matrix pencil algorithms for isolating both non-dispersive and dispersive arrivals in the wavetrain. Computational results for the formation compressional, fast-shear, and slow-shear slownesses obtained from synthetic waveforms in a wellbore with deviations of 0o, 30o, and 60o from the vertical are consistent with the plane wave velocities in homogeneously stressed rock in the far-field subject to the rotated stresses referred to the borehole measurement axes. Compressional slowness changes are primarily affected by changes in the stress along the propagation direction. In contrast, shear slowness changes are equally affected by stress changes either in the propagation or radial polarization direction. Crossing dipole dispersions are observed for all deviations and the magnitude of shear slowness anisotropy is proportional the difference of principal stresses in the borehole cross-sectional plane. A deviated wellbore with the least amount of difference between the principal stresses in the cross-sectional plane is likely to be the most stable trajectory and is characterized by the least amount of cross-dipole shear slowness anisotropy.
Maximising Productivity of Standalone Screen Completions in Complex Multi-Lateral Wells
Authors: Nettleship Gary , Palmer Anthony , Eshtewi Abdullah
Published: March 2015

The Vincent project is a heavy offshore oil field developed by subsea multilateral wells with sand control. This paper will provide an insight into how completion practices were developed to maximize well productivity and how they were balanced against risks for constructing multilateral (ML) junctions.

The fluids used for drilling and cleaning up open-hole laterals can have a significant impact on well productivity in standalone screen applications, especially with respect to sand screen plugging. This paper details the development of open-hole fluid selection and clean up practices for completing long 2000m+ horizontal laterals with standalone screens. The Vincent wells are more complex due to drilling tri-lateral wells that include two TAML level 5 ML junctions requiring open-hole connections. The paper identifies the key risks for installing the ML junctions in a weak formation including risks imposed from clean up practices.

The paper reviews the lessons learned during execution, how the ML junction installation risks were mitigated and how the Vincent wells were delivered with a well performance meeting expectation.
New Generation of Aluminum Drill Pipes Enhanced the ERD Performances in to the Huizhou Field - South China Sea
Authors: Scaruffi W. , Cristofanelli E. , Yu S. , Trocchia A. , Molaschi C. , Merlo A.
Published: March 2015

This paper is to present the results of a important effort and continuous performances improvement into the ERD challenging drilling activity. CACT-OG is the operator of Huizhou HZ 25-4 oilfield in South China Sea, the discovery made in 2005 consisting in a multiple oil bearing The HZ 25-4 field is pertinent to the PSC 16/19, central area of Pearl River mouth basin, and it is located 6 km southwest from the already operating HZ 19–2 platform, in a water depth of 102 meters. A total of 7 wells have been drilled so far, from HZ 19–2 platform in three different drilling campaigns. After the first three wells campaign, a number of technical challenges have been identified within them : ERD drilling experience level, excess torque and drag, shocks and vibrations, hole instability, hole cleaning and resulting pack off, high side force and casing wear, high ECD due to shallow TVD, losses due to the same leak off because of the increase of the measured depth (faults presence). For the second drilling campaign (2009–2011) a new methodological approach was planned including : a new engineering main curvature design, revised operations procedures and the implementation of newer used technologies such as: Aluminum Drill Pipes (first generation) and Continuous Circulating Devices, (e-cd eni technologies).The results were extremely promising in term of drilling risks reduction and cost saving. A further enhancement step has been achieved with the third drilling campaign in 2012. Taking in consideration the achieved experience, and the lesson learned, the operation plan has been fine tuned revising the procedures, and introducing new Aluminum Drill Pipes of second generation, specifically designed for open hole sections. The new methodological approach and the deployment of the new generation Aluminum Drill Pipes (ADP #2 generation) have had as result both: an amazing improvement in drilling performances specially for 12 ¼ section and a consistent budget saving for the overall project. We can say finally that, this specially conceived drilling approach, and the new technology deployment, may represent an impressive step forward for improving the drilling performances in to the ERD wells, helping to maintain the economic threshold of the Development project.
Rock-Fluid Interactions of a Carbonate Bitumen Reservoir Rock Under Steam-Soak Conditions - Importance of Testing Under Reservoir Temperature and Stress Conditions
Authors: Dudley J.W. , Taberner C. , LaMantia B.C. , Zhang E. , McNett J.
Published: March 2015

Thermal recovery processes can generate substantial porosity, permeability and mineralogical changes to carbonate rocks. Understanding these changes is critical to evaluate the success and safety of the process. Tests to evaluate these changes under steam soak conditions have been done on a carbonate bitumen reservoir rock. Thermal testing done in the presence of water at 265°C and 5.1 MPa (740 psi) under unstressed conditions for ~60 days showed considerable fracturing, dolomite dissolution, calcite precipitation, magnesium-clay formation, and carbon dioxide (CO2) generation above 240°C. Calcite precipitation in the matrix porosity and newly formed fractures was extensive. However, reservoir steaming conditions will be at lower temperature (180°C), pore pressure (1.0 MPa [145 psi], with primarily steam rather than water), and under confining stress (5.8 MPa [845 psi] horizontal, 6.7 MPa [970 psi] vertical). A 17-day steam-soak test in a triaxial pressure vessel under these reservoir conditions was done on an uncleaned core sample (~80% bitumen saturation) for comparison. Water/steam flowed through the sample at intervals indicated a relative permeability of 0.3 mD. At the end of the test the accessible (i.e., water filled) pore space was filled with epoxy under stressed conditions. The remaining bitumen was removed post-test before thin section manufacture. Thin sections from the post test sample were compared to thin sections made from untested end trims and adjacent core material, and to ones from the prior unconfined, higher temperature and fluid pressure testing. The sample tested under confined reservoir conditions also shows dolomite dissolution and neoformation of magnesium-clays. The amount of calcite precipitated is minor. However, calcium sulfate (CaSO4) (not observed in the pre-tested equivalent sample) appears as a by-product of the reaction. Newly formed open fractures are not observed in the test under lower temperature, lower pore pressure, confined conditions. This work highlights the importance of mimicking expected reservoir conditions (temperature, pressure, stress & steam) for evaluating thermal decomposition effects on reservoir rocks. Future tests will help to evaluate whether longer duration heating and flow at the lower expected temperature will produce similar reaction products and physical damage (including fracturing) as more bitumen is mobilized and larger surface areas are in contact with steam.
Discrete Natural Fracture Uncertainty Modelling for Produced Water Mitigation: Chuandongbei Gas Project, Sichuan, China
Authors: Hui Mun-Hong , Glass Jerome , Harris Dan , Jia Changqing
Published: March 2015

The Chuandongbei project is estimated to contain a resource base of 5 TCF (1400 × 108 m3) of gas in five Triassic carbonate reservoirs. It is expected to produce at a capacity of 740 MMscf/d (2100 × 104 m3/d) for several years. There is evidence indicating that natural fractures are present in the reservoir: well test deliverabilities are substantially higher than expected from matrix permeability alone, and natural fractures are observed in cores and image logs. These potentially conductive fractures pose the risk of aquifer water breakthrough to wells.

We evaluated the impact of natural fractures on water production using an Experimental Design approach. Traditionally, fractured reservoirs are represented as dual-porosity models that simplify the matrix-fracture interaction. In this work, we instead represent faults and natural fractures explicitly as unstructured Discrete Fracture Models, which are then flow-simulated using the INTERSECT† simulator. We considered uncertain parameters associated with the fractures (density, size, and permeability) as well as matrix permeability and gas-in-place. We also evaluated the trade-off between two different well patterns, designed to mitigate reservoir compartmentalization and water encroachment respectively.

There was a concern that natural fractures would cause early breakthrough from encroaching aquifer water. However, our results showed that fractures can be beneficial to gas production in some situations but detrimental in others. This study highlights the non-intuitive consequences of natural fractures in a gas field that has an aquifer. It also points to the importance of reducing geological uncertainty (e.g., fracture characteristics and matrix properties) for effective mitigation of water production. Finally, our probabilistic approach illustrates a framework to optimize the well pattern in the face of this uncertainty.
Utility of Multiphase Production Logs in Optimising Performance of Horizontal Wells Exhibiting Crossflow
Authors: Al-Shammeri Faleh , Brett Fischbuch , Abd El-Fattah Mahmoud , Bawazir Mustafa , Al-Shabibi Hussain
Published: March 2015

Horizontal wells are increasingly being completed with inflow control devices (ICDs) in order to equalize the flow profiles, avoid water coning, enhance oil production, and minimize or eliminate downhole crossflow. Evaluating ICD completions is important to assess well performance, water entry intervals, completion efficiency, and potential remedial actions. Advanced multiphase production logging tools can be employed to evaluate the effectiveness of ICD completions.

This paper examines case studies of two horizontal wells drilled along well trajectories with large heel-to-toe pressure differentials. These wells were drilled in a large carbonate reservoir with moderate fracturing in areas of high structural curvature, which added to the heterogeneity. Crossflow can occur under static and flowing conditions with sufficient contrast in reservoir pressure along the wellbore. Crossflow is undesirable especially when water enters the wellbore in one region and flows into the formation at another region, thereby reducing oil relative permeability in the latter region. This can adversely affect well performance and ultimate recovery. Advanced multiphase production logs and wellbore simulation are useful in the determining minimum well production rate required to avoid downhole crossflow.

Multiphase production logging profiles were obtained for the two ICD-equipped horizontal wells in this study. These logs demonstrate the efficiency of ICD completions in minimizing crossflow when wells are produced above critical flow rates. However, the problem of crossflow remains when such wells are shut-in or produced at rates below their respective critical rates.

These results show that comprehensive evaluation of wells exhibiting crossflow is necessary to minimize or mitigate crossflow and optimize well performance. Additional ICD design enhancements are recommended to control crossflow below the critical flow rate and to minimize undesirable gas/water production.

Introduction

Horizontal wells are commonly used in the oil industry to accelerate production and lower unit development cost. Horizontal well performance is affected by many factors, including reservoir heterogeneity, well placement and completion design. In heterogeneous reservoirs, the displacing fluid (water or gas) tends to move faster in zones with higher permeabilities, which will cause early breakthrough of unwanted fluids with eventual bypass of some undisplaced oil (Ouyang 2009). This can affect the pressure distribution and hence can cause crossflow between layers.
Scale Squeeze Treatments in Short Perforation and High Water Production ESP Wells - Application of Oilfield Scale Management Toolbox
Authors: Chen Tao , Chen Ping , Montgomerie Harry , Hagen Thomas , Heath Steve
Published: March 2015

Inhibitor squeeze treatments have been regularly carried out to prevent both sulphate and carbonate scale depositions from reservoir to topside facilities in North Sea field since 1990s. Some of the wells, especially for the short perforation, high water production wells and relatively clean sandstone with little amount of clay material, had experienced a relatively short squeeze life with traditional squeeze treatment.

In this paper, an oilfield scale technology toolbox has been introduced to meet the challenge of squeeze treatment for high water production and short perforation ESP well, including scale inhibitor molecular design, squeeze life enhancement technique, squeeze design, inhibitor residual analysis technique, application and deployment techniques. Field trials were carried out with a satisfactory result.

This paper outlines the idea of how a special monomer was introduced into a polymer to provide improved inhibition performance and enhanced adsorption and retention capability, along with squeeze life enhancement technique through crosslinking and bridging capability with other ionic polymer additives. In addition, the squeeze life enhancement techniques through squeeze treatment design, residual analysis and deployment are discussed. A detailed lab test program to qualify the squeeze scale inhibitors will be introduced including brine compatibility, static jar test, dynamic loop test and coreflood test to qualify the scale inhibitor for squeeze application. This polymer scale inhibitor showed good efficiency in both sulphate and carbonates scale inhibition under the test conditions, along with very good adsorption and desorption property without formation damage.

This paper will give a comprehensive study of oilfield scale squeeze treatment for challenged well, which includes molecular synthesis, program of lab qualification, field design, deployment, application and monitoring. In addition, the mechanisms of squeeze life enhancement through molecular design, squeeze life enhancement and squeeze design will be addressed.
Pore Pressure Prediction in Unconventional Resources
Authors: Couzens-Schultz B.A. , Axon A. , Azbel K. , Hansen K.S. , Haugland M. , Sarker R. , Tichelaar B. , Wieseneck J.B. , Wilhelm R. , Zhang J. , Zhang Z.
Published: March 2015

Understanding pore pressure prediction in unconventional plays is important for executing a safe drilling strategy and for accurate production modeling. Experience from several unconventional plays highlights key aspects of pore pressure prediction work that are different from conventional exploration settings. In conventional exploration, the most common source of overpressure is disequilibrium compaction, where porosity is preserved in mudrocks as pore fluids take on additional overburden load. Traditional petrophysical methods use resistivity, sonic and density data to measure porosity and associate it with vertical effective stress (VES), which is overburden minus pore pressure. In unconventional plays, secondary pressure mechanisms and uplift require other methods because of two influences on pore pressure:hydrocarbon generation andvariations in burial and uplift history.

Both of these situations mean that the relationships between vertical effective stress (VES), velocity, density and resistivity will follow unloading paths, not compaction trends. The unloading paths vary depending on the amount of hydrocarbon generated and the amount of uplift. In organic-rich sections, an additional complication arises because pore pressure cannot be de-convolved from total organic carbon (TOC) and gas effects on shale compressional velocity and resistivity. In conventional settings, fluid gradients and contacts are used to translate measured pressure data from one location to another. In unconventional tight reservoirs, the fluids are not connected and this method will not work. Pressure data must be inferred from drilling event and diagnostic fracture injection test interpretations, and a different way to translate data between locations is required. The majority of pressure data in unconventional reservoirs shows that often, the way to translate pressure information from one location to another in the same tight rocks is to use a constant VES. This method combined with understanding variations in uplift history and hydrocarbon generation has been used to successfully predict pressure ranges in multiple unconventional plays.

Introduction

Unconventional resources plays in shale and tight rocks have become a substantial resource in North America. They are now rapidly being explored and developed outside the United States and Canada in a trend that will likely continue to grow. To economically develop these plays, wells must be drilled as cost effective as possible. To produce from these plays and forecast production, the mechanical properties of the rocks and their stress conditions need to be understood to best stimulate and complete the wells. Pore pressure prediction is integral to both of these activities.
Instantaneous 4D Seismic (i4D) - An Innovative Concept to Monitor Offshore Water Injector Wells
Authors: Stammeijer J.G.F. , Davidson M. , Hatchell P.J. , Lopez J.L.
Published: March 2015

Introduction

Time-lapse, or 4D, seismic is frequently used in the offshore to monitor fluid movement processes such as waterflood or aquifer drive. These processes happen at relatively slow timescales (years). As a result, proper monitoring of these effects requires repeat surveys to be acquired every 3 to 5 years or so.

Recent examples in industry show that fast reservoir changes (~months) are also taking place. The observed changes are often associated with water injector wells. For example, Alsos et al (2009) show an example of a water injection well that produced large time-lapse signals in less than 1 year after its startup. Due to cost and other considerations, it is not feasible to repeat field-wide 4D surveys often, nor install permanent monitoring systems in many of those fields. Yet there is a need to monitor such phenomena more frequently, and also with short reaction times.

In the offshore, we propose a new method for time-lapse seismic surveys focused on water injector wells. Our so-called "Instantaneous 4D (i4D)" method aims to acquire dedicated high-quality 4D data with short turn-around time at cost levels low enough to make it affordable to repeat such data acquisition programs reasonably frequently. We have implemented the method as a variation on surveys that use ocean-bottom seismometers. We suspect that our method can also be combined with other ways of seismic data acquisition (for example, permanent reservoir monitoring systems; vertical seismic profiling systems in wells).

Our method is not intended to replace full-field surveys. Rather, it adds small surveys more frequently in between regular full-field surveys to enable better observation of fast 4D reservoir effects along with slow changes (Figure 1). It can be seen as filling the "gap" between the current practice of infrequent full-field surveys, and the installation of the permanent reservoir monitoring system, which can be expensive.
Application of Gibbs Ensemble Monte Carlo to Phase Equilibria of CO2/Hydrocarbon Mixtures
Authors: Iwasaki Satoshi , Liang Yunfeng , Matsuoka Toshifumi , Takahashi Satoru , Okuno Ryosuke
Published: March 2015

Gibbs Ensemble Monte Carlo (GEMC) is a molecular simulation method to predict phase behavior of fluids, such as crude oil and natural gas. It enables us to visualize microscopic structures of fluid phases. In this study, we apply GEMC to phase behavior of CO2/oil systems, where the CO2-rich liquid (L2) phase can coexist with the oil-rich liquid (L1) phase and vapor (V) phase. The L2 phase can have comparable density as the L1 phase. When the L2 phase is dense enough to extract light and intermediate hydrocarbons, CO2 flooding can achieve high displacement efficiency of more than 90%. A clear understanding of the L2 phase will help us design CO2-solvent injection processes. However, little is known about its microscopic structures and corresponding dynamic properties (i.e., viscosities and diffusion coefficients), apart from densities and phase compositions. The GEMC method is used to calculate phase equilibria of CO2/C16H34 mixtures at different pressures at 305 K, which are close to the critical point of CO2. Vapor-liquid phase equilibrium is predicted at pressures lower than 75 bar and liquid-liquid phase equilibrium at higher pressures up to 170 bar, where the density of the L2 phase is around 0.868 g/cm3 and that of L1 phase around 0.871 g/cm3. These results are in good agreement with the previous experimental data. By further adding CH4 and C2H6 into the mixture, liquid/liquid/vapor equilibrium was observed. The mole fraction, density and structural properties such as pair distribution function (which is directly related to the X-Ray diffraction), molecular clustering, and aggregation status of the three different phases are presented. Currently, we are extending our calculations to other CO2/hydrocarbon systems and calculating viscosities of two different liquid phases using Molecular Dynamics simulations with the atomic model used for GEMC.
Enabling Large Model of Reverse Time Migration
Authors: Lu Ligang
Published: March 2015

The extreme computational complexity of modern seismic imaging techniques has led to a decades-long search for the most efficient algorithms, the best optimization techniques and the most suitable hardware platforms on which to run these algorithms. The purpose of our study is to advance this search by exploring the potential of the new Blue Gene/Q (BG/Q) supercomputing system for Reverse Time Migration (RTM) imaging. Our study analyzes BG/Q's performance scalabilities over both imaging model size and number of computing nodes. Our end-to-end RTM implementation includes a 3D isotropic model, absorbing boundary conditions, a 9x9x9 stencil, forward and backward passes with application of source and received terms, snapshot storage and imaging condition. Our implementation uses domain partitioning of a single model over hundreds of nodes, which allows us to run models much larger than are common today. For example, we can easily run a 3D model of 20483 points. For the models tested, we have observed nearly perfect performance scaling over hundreds of nodes and are exploring scaling beyond that point. Even with initialization, data input, and image output, we have achieved an end-to-end throughput of 580 million stencils per second per node (or 590 billion stencils per second per rack). Furthermore, we achieved a 14.93x rack-to-rack performance improvement over the previous generation, BG/P. Our implementation exploits all levels of parallelism available, including MPI, OpenMP for multithreading, and built-in intrinsics for vector operations. We avoid the need for scratch space on disk by storing snapshots in memory. Our paper shares insights and experience on how to efficiently make use of BG/Q's HW resources to advance the state-of-the art of industry practice. It provides a guiding example for enabling seismic imaging algorithms using BG/Q to achieve an unprecedented level of performance.