bluuebunny/crossref_metadata_2025 huggingface dataset:
Separation and Recycling of Used Oil-Based Drilling Fluids
Authors: Farinato Ray , Masias Henry M. , Garcia Diana , Bingham Richard , Antle Glenn David
Published: March 2015

A novel approach has been taken to separating, recovering and recycling the oil-continuous phase from used oil-based drilling fluids. The method is based on destabilizing and aggregating the suspended solids and brine droplets through the application of polymers and surfactants in a controlled mixing device. The aggregated material may then be centrifugally separated using traditional solids-control equipment. This allows recovery of the oil-continuous phase, which may then be recycled into another oil-based drilling fluid. Laboratory data and field case studies will be presented that substantiate the efficacy of this solid-liquid separation method. Microscopic analyses of the aggregated solids support a proposed mechanism based on preferential wettability.

Background

Several aspects of petroleum production rely on solid-liquid-liquid separation of oil-continuous dispersions comprised of discrete aqueous and solid particulate phases. Such mixtures occur as drilling fluids, as produced fluids, at various stages in upgrading feedstock for refineries, and as a variety of waste streams derived from drilling, production and delivery operations. The efficiency and speed of mechanical separation of colloidally dispersed materials is greatly improved by aggregating fine particulates and coalescing liquid droplets as long as their densities are sufficiently different from the continuous phase. Improving solid-liquid-liquid separation in petroleum applications can have great economic and environmental benefits. This paper discusses a chemical and mechanical treatment scheme employing surfactants and inverse polymeric emulsions to concurrently improve particulate flocculation and droplet coalescence, thereby improving solidliquid-liquid separation in a conventional centrifuge.

The petroleum industry necessarily produces large quantities of complex mixtures of oil, water and solids either by design, as a consequence of natural resource recovery, or as a byproduct resulting from normal operations. Management of these fluid streams is not only good practice, but it can also make good economic sense, especially if components can be recycled. Drilling fluid management practices involve minimization, recycle/reuse, disposal or some combination of these practices (1). Strategies that minimize or dispose of waste is only one of cost avoidance, whereas strategies that rely on recycle/reuse can produce positive economic as well as environmental benefits. Current practices for disposing oily wastes include:onsite burial (pits, landfills)bioremediationoffsite disposal to commercial facilitiesre-injectionthermal treatment

Current practices to recycle/reuse oily byproducts include:recycling fluidsroad spreadingreuse of cuttings for construction purposesuse of oily cuttings as fuel
Innovative Mercaptan Scavengers: First Field Application
Authors: Passucci Claudio , Grazioli Gianfranco , Carniani Carlo
Published: March 2015

Mercaptans are naturally occurring components of sour crude oil and natural gas condensate. When present in appreciable concentrations, they generate a very disagrenable smell which can be a nuisance to operators and to surrounding communities. Regulatory authorities aften require that mercaptan odors be controlled. A practical example of that has occurred to a gas field located in southern Italy which was suffering nuisance odor problems originating from a gas well whose fluid contained over 500 ppm total mercaptans. Production from this and several surrounding wells is collected in a shared collection tank, centrally located near officies and visitor entrances, where fluids undergo initial condensate/water separation. Despite dilution from well fluids containing far less mercaptan, the collection tank still emitted odors. The tank averaged 14Sm3 of condensate throughput per day and contained, on average, approximately 60 ppm total mercaptan. There was no issue about condensate delivery specification of mercaptan level, since the condensate can be diluted in other streams but the odor control issue was an opportunity to test the scavenging performance in the perspective of future, large scale mercaptan content management in other production sites. Contractor was involved as consultant to consider options for reducing mercaptan odors emanating from the condensate collection tank.

On the basis of cost- performance and ease of implementation, an innovative mercaptan scavangers was chosen as the preferred means to reduce odors from the tank.

The use of mercaptan scavangers is new to the oil industry.

The mechanism is a chemical reaction which converts mercaptan into a different chemical species. In this way the amount of mercaptan in the condensate is reduced and the unpleasant odor is controlled; if a specification exist for the level of mercaptan in the condensate, it allows this to be met without introduction of any additional unit operation or process.

Even if it isn't the case for the present case history, mercaptan scavangers are a very promising method to control streams that are out of specification.

The targeted key performance indicator (KPI) for this application was a reduction of mercaptan levels in the condensate by 50–75%. After considering several potential injection sites, it was agreed that the new mercaptan scavenger would best be continuosly injected directly into the mixed fluids collection tank.

From this point, the most efficient and effective mercaptan scavenging treatment could be realized, and condensate could then be readily transferred to the sales tank.
Surface Development Aspects of Alkali-Surfactant-Polymer (ASP) Flooding
Authors: Weatherill Alan
Published: March 2015

This paper highlights the differences between an Alkali-Surfactant-Polymer (ASP) Flood project and traditional Exploration and Production (E+P) developments from an Engineering and Operations perspective. It lists the common problems encountered, drawing on published and unpublished sources, and describes their root causes. It proposes strategies for avoiding the problems in future ASP flood applications.

Introduction

A number of Shell-affiliated operating companies have identified Enhanced Oil Recovery by chemical injection as an option for accessing the remaining oil in place and extending field life. Several pilots have been implemented and more are under development. Currently the most advanced of these is a full-scale Polymer Flood that will soon start in Marmul in the Sultanate of Oman.

In general these companies are working to meet the challenges typical of late-life field production, namely: handling increasing water production, minimizing chemical usage, prioritizing well interventions, optimizing equipment maintenance strategies and assuring technical integrity and plant availability. The organisation and the skill set of the staff running these fields reflect this focus.

Implementing a chemical flood requires special skills and a different focus. The project is somewhat experimental because of the unknowns about how the chemicals will behave in the reservoir. The process line-up and equipment list include items not seen in a typical Exploration and Production company. The standard of cleanliness and the degree of sampling and monitoring are more like those seen in a specialty chemicals or food processing plant. This paper summarizes what is different about chemical EOR for the surface engineering and operations team and it provides an overview of the skills and the team culture needed to succeed.

What is ASP flooding?

This paper considers Alkali-Surfactant-Polymer (ASP) flooding, as this encompasses a broad range of chemicals and technologies. Most of the challenges associated with, for example, polymer flooding, are a subset of those for ASP flooding. In an ASP flood, a series of chemical slugs sweeps the reservoir from injection wells to producing wells. The sequence of injection is:Softened water. This provides a buffer in the reservoir between the existing water (which, in late field life, will be a mixture of connate water and water flood water) and the following ASP slug. Generally this existing water is hard and without this buffer the Alkali in the ASP slug would precipitate the divalent ions as scale. These divalents also precipitate the surfactant, which is usually anionic, and interact with polymer to reduce its viscosity.
Fast track lithological interpretations applied to detailed evaluation of Norwegian Sea basin
Authors: Vernay Paul , Mathieu Jean Philippe , Leduc Jean Pierre , Martinez Lionel , Bastien-Dubes Alice , Fourmentraux Philippe
Published: March 2015

Geopetroleum studies, assessment of operated or non -operated acreages, and evaluation of new opportunities use correlation sheets and facies distribution maps. These documents are elaborated from lithological interpretations based on conventional logs (gamma ray, density, neutron, sonic, resistivity). The main challenge the geologists can face is to interpret huge intervals covered by heterogeneous log data in numerous wells in a very short space of time. Currently available software packages cannot be used as they lack the tools required to automatically analyze, standardize and process simultaneously all the wells. Interpretations are usually carried out on a small number of selected wells, which are processed one after the other. A leading edge methodology supported by dedicated software tools is presented here. It is composed of five steps: harmonization of log names, units and sampling rates; cleaning of logs; multi-well pre-processing; faciological modelling; multi-well quality control and facies maps creation. It was developed to process consistently all the available data sets and obtain homogeneous and reliable lithological evaluations in a shorter time. The interest in the implementation of such a method is illustrated from the example of a petroleum synthesis which was realized on 160 wells in the mid Norway Haltenbanken-Dønna Terrace areas. This method and the associated statistical tools have been also successfully applied in many other petroleum contexts and many geographical areas including the Middle-East. The use of all available logs improves the quality of the results and assures homogeneous interpretations. A significant reduction in costs and durations is observed in all the studies that have applied this methodology. This positive effect increases with the size of the well data base to be processed. Typical reduction factors from 3 to 10 are experienced. In addition, studies that would be prohibitively long and expensive with classical methods become possible.
Reservoir Development Modeling Using Full Physics And Proxy Simulations
Authors: Yang Yahan , Davidson Jeffrey Edward , Fenter David James , Ozen Ozgur , Boyett Barbara A.
Published: March 2015

This paper describes a modeling technique for reservoir development using full physics and proxy simulations. Traditionally, full physics simulation involves gridding and discretization, fluid property calculations, displacement modeling, assembling matrix equations, and solving the equations over time. In the gridding step, the reservoir is divided into a collection of cells on which the governing equations for multiphase flow are rewritten in discrete form. Fluid property and displacement modules compute various quantities and their derivatives needed for assembling the matrix equations during time stepping. For reservoir simulation, the system of matrix equations often is quite large and may contain hundreds of thousands of unknown variables. Solving such a system is a computationally intensive task. As a result, a simulation run may take days or even weeks for large models to complete. To improve the computational time, proxy simulations have been considered in recent years as an alternative to full-physics simulation. In general, proxy simulations achieve higher computational efficiency at the expense of accuracy, and are constructed by either reducing the model size or simplifying the physical behavior of fluid flows.

In this work, we combine full physics and proxy simulations to take advantage of the strength of each approach. The proxy technique employed is known as profile generator. It simplifies the reservoir into material balance tanks and well source/sink terms into a set of tables known as type curves, which relates production GOR, WCUT, etc. to EUR and other parameters. With full physics or proxy simulation, flows in wells and surface facilities can be modeled and production/injection rates allocated using rule-based or optimization-based well management.

Integration of grid-based simulation and profile generator in a single modeling system makes it possible to easily generate type curves and validate results from proxy simulations. For large assets containing multiple reservoir systems or fields, this technique allows engineers to build a mixed simulation project containing grid-based models for some reservoir systems and type curve-based models for the rest, thus obtaining a balance between accuracy and computational efficiency. Using this new technique, engineers are able to more efficiently evaluate facility constraints and facility upgrade options, quantify impact of changing a field's startup time on facility capacity, and optimize production from multiple fields.
First Australasian Batch Conductor Drilling - World Record Size - Ahead of Time Estimate
Authors: Niedermayr Michael , Pearse Jack , Tan Ming Zo , Utama Budi
Published: March 2015

Since the turn of the millennium, non-retrievable drilling with casing technology has been introduced to the Asia Pacific region. Soft formations encountered in offshore drilling environments have promoted the successful application of casing drilling technology for conductor and surface casing installation1,2,3.

The Weatherford system employs a simple aluminium based casing drill shoe and float collar assembly, driven by a surface drive system that transmit torque from the top drive to the casing string4. Upon reaching targeted casing shoe depth, the cementing operation can commence almost immediately. The next conventional drilling assembly can then drill out the casing drilling assembly using a traditional PDC or rock bit without requirement for a special drill-out bit.

The Maari Development Project in New Zealand is situated in an ideal soft drilling environment that is within the capability of the drillable drill shoe. During the project planning stage, non-retrievable drilling with casing technology was highlighted as a viable technology to improve drilling efficiency, reduce cementing times, protect the weak shallow formations the platform foundation depends on, and reduce potential risks. Substantial engineering effort and time have been invested to tackle all relevant technical issues.

This paper presents the Maari Project's 24" conductor drilling programme, covering the entire process from the planning stage through to the execution, which resulted in successfully installing and cementing nine strings of 24" conductor ahead of the time allocated to conventionally drill, case, and cement eight strings.

Background

The Maari oil field in permit area PMP 38160 was discovered in 1983. Through various acquisitions PMP 38160 is now operated by OMV New Zealand Limited (69%) on behalf of its joint venture partners Todd Maari Limited (16%), Horizon Oil International Limited (10%), and Cue Taranaki Pty Ltd (5%). The permit contains the Maari discovery and is located close to another oil discovery the Manaia field in block PEP 38413.

Five production and three injector wells were planned for the initial development. In addition, provision was made for the construction of a further 4 wells at a later stage in Project life. All these wells can be drilled from or tied back to the wellhead platform (WHP) "Tiro Tiro Moana", which is equipped with 12 drilling slots. The waxy nature of the crude requires heating downhole, on the wellhead platform as well as the FPSO "Raroa" to successfully transport the crude.
Fluid Characterization and Modeling of Compositional Variation, Dukhan Field, Qatar
Authors: Gupta Deepak K. , Lawrence John , Abdul Majid Mohamed Naguib , Wahlheim Thomas A.
Published: March 2015

The paper describes the development of an equation of state (EoS) for two reservoirs of the Dukhan field, the Arab C and the Arab D reservoirs. The paper also describes the development of compositional maps for both the reservoirs. In absence of pre-production samples, an iterative approach was used to estimate composition at a known depth for the Arab C reservoir. Equilibrium contact mixing (ECM) method along with an iterative approach was used to estimate oil composition at the gasoil contact depth for the Arab D reservoir. By examining the heptanes-plus (C7+) properties of the samples collected from the depleted Arab C reservoir, existence of compositional gradient in the reservoir at discovery conditions was confirmed. It was shown that the existence of near constant C7+ properties in the oil-column of the depleted Arab D reservoir does not preclude the existence of compositional gradient at discovery conditions. By incorporating the gravity segregation and the thermal diffusion effects, oil composition maps for the Arab C and the Arab D (excluding Diyab sector) were developed. It was shown that the inclusion of thermal diffusion effect resulted in very small changes in component concentration for the Arab C reservoir. The large saturation pressure difference between three sectors of the Arab D and the fourth sector, Diyab was then modeled using molecular diffusion. For the Arab D gas-cap, the gas composition at the gas-oil contact depth was calculated by utilizing the tuned EoS and the oil composition at the gas-oil contact. The gravity segregation and the thermal diffusion significantly changed pentanes-plus (C5+) and C7+ distribution in the gas-cap gas with 23% and 30% reduction in mole% from the gas-oil contact to the crest of the structure.

Introduction

The large, mature Dukhan Field is located onshore Qatar, approximately 80km west of Doha. It is a North-South plunging anticline approximately 70km long by 8km wide (Figure 1)1. The field was discovered in 1939 and first production occurred in 1949. The field has more than 750 well penetrations. The major oil reservoirs are the Upper Jurassic Arab C and Arab D. There are lesser amounts of oil and gas in the Middle Jurassic and non-associated gas in the Permo-Triassic Khuff formation.
An Integrated System for Pipeline Condition Monitoring
Authors: Strong Andrew Peter , Lees Gareth , Hartog Arthur H. , Twohig Richard , Kader Kamal , Hilton Graeme , Mullens Stephen , Khlybov Artem , Sanderson Norman
Published: March 2015

Pipelines are at risk from external threats including third-party intrusion, societal development and ground movement in addition to the ongoing potential for leaks due to corrosion or other causes. Although the appropriate use of internal inspection practices and regular survey of coating and cathodic protection systems will give timely information on any deterioration in pipeline condition, external threats can be unpredictable.

In this paper we present the unique and innovative pipeline and flowline integrity monitoring system developed by Schlumberger in collaboration with BP. The system uses optical fiber distributed sensors to provide continuous, simultaneous distributed measurements of temperature, strain and vibration for the detection, monitoring, and location of events including:•Third-Party Interference (TPI), including multiple simultaneous disturbances•Geo-hazards for example landslides or subsidence•Gas and oil leaks•Permafrost protection

Optical fiber sensors are widely used and have over the past 20+ years built a track record in the Oil & Gas industry in applications including pipeline condition & leak monitoring, optimization of oil well productivity and LNG plant leak detection and cool-down process monitoring.

The solution provides a unique and proactive approach to pipeline integrity management. It performs analysis of a combination of measurands to provide the pipeline operator with an event recognition and location capability, in effect providing a hazard warning system, and offering the operator the potential to take early action to prevent loss.

Through the use of remote, optically powered amplification, an unprecedented detection range of 100 km is possible without the need for any electronics and therefore remote power along the pipeline. A system can thus monitor 200 km of pipeline when configured to monitor 100 km upstream and downstream from a single location.
Experience in Low-Frequency Spectral Analysis of Passive Seismic Data in Volga-Ural Oil-Bearing Province
Authors: Birialtsev Evgeny , Eronina Ekaterina , Rizhov Dmitriy , Rizhov Vasiliy , Shabalin Nicolay , Vildanov Alik
Published: March 2015

In this paper, we consider our experience with passive low-frequency seismic exploration for oil and gas. We present the data on the phenomenology of the effect, sets out possible geophysical mechanisms of effect, present results of numerical simulations in comparison with the observed results; we describe the main approaches to the interpretation of seismic data studies and give a brief overview of geological results of our microseisms research in the Volga-Ural oil province.

Introduction

Geological exploration in areas of old oilfields such as field Romashkino in the territory of the Republic of Tatarstan has a number of features (Mouslimov et al., 2007). Targets of geological exploration are predominantly the exploration of small fields and exploration of producing fields in the boundary zones. These objects are characterized by complex geological structure, structural traps have a small amplitude, small size, have numerous complications such as lithological replacement and tectonic faults.

Under these conditions, the effectiveness of structural seismic studies was decreases. Combination of structural seismic method and methods of local prognosis of oil-bearing is necessary to improve the efficiency of drilling. However, traditional non-seismic methods - high-precision gravimetric, electrical, geochemical studies have sufficiently large radius of the study and also not effective for small search objects.

The method of passive seismic ANCHAR (Aroutyunov et al., 2001) was tested in 2002 in the Republic of Tatarstan as a method of local prognosis of oil-bearing for solve this problem. According to this method in the spectrum of microseisms over natural gas and oil deposits should be observed pronounced spectral maxima in the range of 1–10 Hz. Work was carried out in two areas and have produced mixed results. On the one hand, the predictions of oil-bearing by this method have the conflict with the existing ideas about the geological structure and the drilling has not been undertaken for this predictions. On the other hand - microseismic noise over oil deposits and outside them had obvious differences. Mixed results and the need for an effective method of local prediction led to a large complex of experimental and theoretical studies of the structure microseismic field as a possible indicator of oil saturation. In this report we present the results of science research and practical application of passive microseismic research to address the various geological problems of Petroleum Geology.
Structural Control on Permo-Triassic Deposition in the Central Arabian Plate: a Multi-Scale Approach.
Authors: Zampetti Valentina , Borkhataria Ravi , Koopman Anton , Vroon Marietta , van Oosterhout Cees
Published: March 2015

A multi-scale analysis integrating structural concepts, local seismic data and well correlations across the Central Arabian Plate demonstrates that the thickness and facies distributions of one of the most important hydrocarbon reservoirs in the Middle East, the Khuff carbonate, are strongly controlled not only by the structural relief at time of deposition but also by the reactivation of the basement structural fabric related to Permo-Triassic tectonic events.

Stratigraphic and sedimentological data indicate that on a regional scale, the Khuff carbonate shows a wide variety of depositional environments (with facies ranging from coastal plain anhydritic claystone, tidal flat/lowto-high energy lagoonal deposits to open-marine dolostones alternating with grainy limestones and high-energy shoal-dominated dolostone/thick grainy limestones) and thicknesses (from near zero at the pinch-out of siliciclastic facies in central Saudi Arabia, to more than 400 m (1300 ft) in the Ghawar field in northern Saudi Arabia, expanding to 800 m (2600 ft) in the North field, Qatar and to nearly 1000 m (3300 ft) in the eastern United Arab Emirates).

Pre-Khuff basement-related anisotropies on the Arabian Peninsula are interpreted to have formed as early as Late Neo-Proterozoic to Ediacarian time and to follow three main trends: N-S (Nabitah),NW-SE to WNW-ESE (Najd),NNW-SSE to NW-SE (Mesopotamian).
Leveraging a Common Infrastructure to Support Qatar's Rapid LNG Expansion
Authors: Al-Amoodi Ahmed , Felton Keith C. , Kasim Kamal
Published: March 2015

The State of Qatar is rapidly expanding to capture almost one-third of the world's LNG market. By 2010, LNG exports from the State of Qatar are projected to reach 77 million tonnes per annum. In addition to the LNG production, there will be a sizeable quantity of by-products - condensate, propane, butane, and sulfur - as a result of the LNG production. These by-products are expected to reach production rates of approximately 80,000 m3per day (500,000 barrels per day) of condensate, 20,000 tonnes per day of propane, 13,000 tonnes per day of butane, and 12,000 tonnes per day of sulfur.

To support this expansion, the State of Qatar has embarked on a pioneering approach to the storage and loading of LNG as well as its by-products that will serve as an example of significant capital investment savings, operational flexibility, and reduced land requirements. Traditionally, dedicated storage and loading facilities (infrastructure) have been designed and built to support a specific LNG production train and its associated by-products. The State of Qatar's innovative approach has been the design and construction of a fully integrated common infrastructure to support all of the joint venture owned LNG production trains as well as other gas related projects in Ras Laffan Industrial City. This paper will describe the unique aspects of this fully integrated infrastructure, its benefits, and the complexities and challenges associated with making the vision of a fully integrated LNG infrastructure come to fruition.
Optimal Well Placement In Long Horizontal Developments: Al Khalij Case
Authors: Meyer Nicolas Etienne , Socquet Juglard Florian , Dehesdin Remi , Narayanan Ramdas
Published: March 2015

When drilling horizontal drains in a thin layer environment, one of the main challenges is to maximise the reservoir exposure, which means remaining in the pay zone as long as possible and at the same time avoiding or at least identifying any possible water conductive events. Considering that an angular difference of only one degree between the well bore axis and the apparent dip of the formation along the well path results in about half a metre vertical shift every drilled stand, remaining within a one or two metres thick reservoir requires a better precision for an optimal reactivity in the geosteering process.

The first requirement in this type of application is an accurate geological model that ideally features the layer geometry as well as the distribution of reservoir characteristics such as resistivity, porosity, radioactivity, saturation… etc. A good knowledge of the structural scheme is necessary, including fault frequency with the order of magnitude of their vertical throw, the frequency of structural undulations with an idea of their wavelength… In addition, it is necessary to visualise in real time the well within the model. Then, it becomes possible to anticipate possible structural undulations and to pro-actively make the necessary decisions to properly steer the drain within the reservoir.

The industry proposes two types of LWD resistivity imaging tools which may be considered for this purpose:• The azimuthal electromagnetic propagation resistivity imagers,• The laterolog type resistivity borehole imagers

The laterolog type resistivity imagers have the essential drawback that they only work in conductive mud systems. But on the other hand, they are able to provide very high resolution images. This enables the accurate picking of sedimentary and structural events such as bedding, dips and fractures.

Al Khalij field, offshore Qatar, features a carbonate layer-cake of alternating oil bearing and water bearing limestone reservoirs. Each oil bearing reservoir layer is about 2m to 5m in thickness. Surrounding water-bearing layers show similar porosity values but much finer grain size and have no physical limits with oil bearing reservoirs. The present paper describes an integrated method developed to achieve an efficient geosteering of long horizontal drains which may reach 3,000m to 4500m in order to maximise the reservoir exposure along the well path.
Smart Integrated Chemical EOR Simulation
Authors: Fadili Ali , Kristensen Morten Rode , Moreno Jaime
Published: March 2015

Chemical Enhanced Oil Recovery (EOR) techniques have recently seen a new revival owing to high oil consumption and favorable conditions that drove the oil price in a range where use of chemical is becoming economically viable. Advancements in technologies and understanding of past failures also contribute to this revival. However it appears that there is a lack of a comprehensive tool which allows exploration and assessment of combined chemical EORs at the field scale, and which can be driven dynamically to simulate realistic field applications.

In this paper we propose a set of integrated models for polymer-brine, surfactant, alkaline and foam including ions exchange for calculating effective salinities. These models can be driving by a set of flexible field management functionalities which allow a dynamic optimization of the use of the chemicals to maximize oil contact and ultimately its recovery.

A work flow to assess the balance of viscous, capillary and gravity forces involved in the EOR process is proposed to pre-screen the type of chemicals needed to modify the force balance. This approach will precede and guide the dynamic optmization.

Introduction

Exploration for hydrocarbons is reaching global frontiers, and the short- and long-term challenges will be to maximize recovery from existing fields. As an important subset of the enhanced oil recovery (EOR) offering, chemical EOR techniques have developed as an economical and viable alternative for increasing oil recovery. Their success though relies heavily on a thorough understanding and ne-tuning of the chemical interactions between the injected chemicals, the fluids in place, and the rock. These interactions eventually determine optimal injection and production scenarios and ultimately the total increment in oil recovery.

Modeling of processes such as alkaline-surfactant-polymer (ASP) flooding, low salinity water flooding, solvent flooding, and foam injection for gas mobility control require a detailed description of the EOR agent interaction with the rock and reservoir fluids. This includes flexible modeling of solution viscosities, non-Newtonian behavior,

permeability reductions due to adsorption (e.g. in polymer flooding), capillary de-saturation effect due to decreasing oil-water interfacial tension, chemical losses to the formation due to adsorption, change of wettability characteristics, and chemicals degradation, to mention just a few.

However, the success and cost-effective design of EOR projects relies on the ability to model complex combinations of these processes in realistic reservoir settings while taking into account limitations in surface equipment, project economics, and consistency in the numerical solution. Being able to monitor the chemicals within the reservoir and being able to adapt the injection and production schedule automatically become key elements in optimizing chemical EOR processes.
A High-Resolution Chemostratigraphy Application in Carbonates. A case study in the Cretaceous Mishrif reservoir, Minagish Field, Kuwait
Authors: Gezeeri Taher Mohd Nabil , Hamim Ahmed Ibrahim , Zereik Rachad , Hughes Simon Nicholas , Scheibe Christian
Published: March 2015

The Upper Cretaceous Mishrif reservoir in Minagish field is currently being developed by Kuwait Oil Company (KOC) using a horizontal drilling program. The Mishrif reservoir is approximately 300 ft thick across the field, with an average net pay of 170 ft in the upper layers. The reservoir porosity varies from 15 to 30%, and permeability ranges from 0.001 to 17mD. The first Mishrif horizontal well was drilled from west to east in the northern block of Minagish field. The well appears to have penetrated several generations of faults and associated fractures (early northwest to southeast, intermediate northeast to southwest, and possible late northwest to southeast. The production rate has been poor (approximately 500 bbl oil per day). An evaluation of the image logs indicated that only two of the reservoir layers appear to be fractured, whereas other layers are muddy and devoid of fractures, even near faults. To address the structural and stratigraphic uncertainties of the Mishrif reservoir, a high-resolution elemental chemostratigraphy study was performed on cored wells prior to additional drilling. The study produced a robust elemental zonation primarily based on variations in CaO/MgO, CaO/Sr, and MgO/Sr (carbonate-related), SiO2/Al2O3 and Zr/TiO2 (detrital-related), and Br, S, Na2O, and Cl (diagenetic phases and/or formation waters). The study results were used to calibrate a portable laser-induced breakdown spectroscopy (LIBS) instrument, which was used for near real-time chemostratigraphy at the wellsite to assist in geosteering operations. The recent horizontal well penetrated a highly faulted section in Mishrif layer 2, with significant changes in dip related to faults. LIBS technology assisted in actively optimizing the well path in the porous limestone zone, only 5 to 10 ft thick, within this structurally complex regime. The distribution of possible fracture swarms and faults was reflected by abrupt changes in the geochemical profiles (MgO/CaO, S, [Ni+V+Fe2O3]/Al2O3, Na2O, and Cl). This well achieved a new record for the longest horizontal drain hole in Kuwait.
P-wave Seismic Azimuthal Anisotropy for Detection and Prediction of Fractures in a Middle Eastern Carbonate Reservoir
Authors: Zelewski Gregg , Lu Chih-Ping , Tsenn Michael C. , Mitchell John , DeGraff James Michael
Published: March 2015

Management of carbonate reservoirs often needs to go beyond characterizing matrix properties to include fault and fracture effects, which can significantly impact water break-through and oil sweep efficiency. Predicting the flow impact of faults and fractures can benefit from the identification of these features from seismic data. Given their anisotropic nature, fracture trends in carbonate reservoirs have a reasonable chance of being detected with seismic methods. We will present the use of P-wave prestack seismic azimuthal anisotropy inversion for the detection and prediction of fractures in a Cretaceous Middle Eastern carbonate reservoir.

Introduction

The study of azimuthal anisotropy using prestack P-wave seismic was shown to be useful in the identification of open fractures by Lynn et al, 1996. More recent work in Middle Eastern carbonate reservoirs, using prestack P-wave seismic for estimating azimuthal anisotropy to detect fractures, was done by Luo et al., 2005, Holmes and Thomsen, 2002, and Roberts et al., 2001.

Open fractures in the subsurface, when vertical and aligned, may be detected with seismic anisotropy using azimuthal AVO inversion of P-wave data. The azimuthal AVO inversion method presented here is based on Ruger's equation (Ruger and Tsvankin, 1997), which describes the observed reflectivity (R) as a function of normal incidence amplitude (A0), AVO slope (B0), anisotropy magnitude (B1), anisotropy orientation (f0), and noise (ni):

R(?i , fi) ~ A0 + [B0 + B1 cos 2(fi - f0)] sin2 ?i + ni

Inversion of Ruger's equation yields four attribute volumes (corresponding to A0, B0, B1, and f0). Additionally, we developed a confidence term for uncertainty analysis.
Accurate generation of seismograms on fractured reservoirs
Authors: Thore Pierre , Tarrass I. , Gibson Richard L. , Lisitsa Vadim V. , Reshetova Galina V. , Tcheverda Vladmir A.
Published: March 2015

A major challenge in carbonates environments is to map heterogeneities which have a strong impact on oil and gas production. For example in many carbonate reservoirs, matrix porosity contains the oil in place but the permeability is mainly provided by fracture corridors. In some carbonate reservoirs, such as Kashagan field in Kazakhstan, the oil in place is essentially contained primarily in karstic caves and conduits. Therefore being able to precisely locate these heterogeneities and possibly characterize their properties is essential in these environments.

Various techniques have been developed recently to locate and characterize these heterogeneities, by detailed analysis of the elastic signals recorded in seismic experiments. Among them one can think of the scattering index presented by Willis et al (2004) or all the imaging techniques developed recently under the generic name of interferometry.

The first step in all processing or inversion procedures is to be able to accurately simulate the forward problem, and it is therefore of paramount importance to be able to accurately model the scattering related to fractures and caves. The numerical and computer constrains even on very large clusters limit the resolution at which a model can be described. The current practice for finite difference modeling is to use 20m grid cells for acoustic modeling and spatial discretization leading to cells 10m in size for elastic modeling. In these cases, heterogeneity associated with fracturing on smaller scales must be upscaled and distributed in an equivalent medium, which will reproduce varaiations in traveltimes and changes in reflection coefficient but will neglect the scattered wavefields that are the subject of the recently developed methods for characterizing fracture distributions. In this paper, we present a full waveform modeling technique based on a new approach of finite differences which allows simultaneous simulation of both macro- and micro-scale heterogeneities. This algorithm is based on a multi grid approach that models the seismic response of a shot point over a large size model containing micro scale heterogeneities in a reasonable time frame (i.e., several hours on a modern cluster). We show various examples of the signals related to fractures and their importance in terms of heterogeneities interpretation, and we also examine results of simulations using 3-D modeling based on the Born approximation to help interpret and explain the synthetic seismograms.

These new numerical results will have significant advantages over previous results that rely on approaches that replace the detailed spatial variations of elastic properties with media with altered velocities and densities.
Correlation between Rock Physical Properties, Sedimentological, and Diagenetic Characteristics of Late Cretaceous Carbonate Rocks in the Middle East
Authors: Alsuwaidi Mohammad Eid , Vega Sandra , Steuber Thomas
Published: March 2015

This paper aims to establish correlations between petrophysical properties, sedimentological, and diagenetic characteristics of carbonate rocks from well cores of the Lower Cretaceous Thamama Group. A previous petrophysical study by Saleh, et al (2008) on the same well cores revealed that four plug samples out of 17 have a strong anisotropy relation of shear velocity (Vs) and permeability. Based on these results, we conducted a thorough sedimentological and petrographical study to explain the unique characteristics of these samples.

We performed a full 170 feet core description of a vertical well to study the lithological and diagenetic background of the seventeen samples. It was assured that the core plug samples represent all types of lithofacies observed in the core description. Thin sections from the samples were also prepared and described, and well log data were analyzed.

The well core description resulted in the identification of five lithofacies: bioclastic wackestone with low cementation, Bacinella floatstone, requieniid rudist floatstone/rudstone, highly cemented orbitolinid wackestone/packstone, and thin bedded shale.

Three out of four samples, that have Vs and permeability anisotropy relationship, belongs to the bioclastic wackestone. The fourth sample belongs to the requieniid rudist floatstone/rudstone. It contains dominant matrix and scattered requieniid rudist fragments.

Thin section description showed that samples with anisotropy relation of shear velocity and permeability are characterized by: a pore system that is homogenously distributed (microporosity), without significant influence of cementation, abundance of allochems, and other type of porosities, abundance of matrix, lack of skeletal and non-skeletal allochems, and low cementation. On the other hand, samples that have no clear anisotropy relationship have abundant bioclasts are highly cemented and have dominant intraparticle, interparticle, vuggy, or channel porosity.

Crossplot analysis of well logs and core description gave the following results:• Core horizontal permeability and porosity correlation has three main trends interpreted according to different degrees of cementation.• In general, as horizontal permeability of core increases, the compressional wave velocity decreases twice as much as the shear wave velocity, taking into account the preferential permeability direction.
Inline separation pilot to support Produced Water Injection in PDO
Authors: Verbeek Paul , Al-Moosani Ashiq
Published: March 2015

This paper describes a technology development project that resulted in the deployment of a fully operational in-line/compact separation prototype skid, which is the first of its kind in the industry. The project provided the surface facilities necessary to successfully arrest the decline of production in a North Oman oil field through Produced Water Re-Injection in a timely manner. The modular approach proves to be a concept that may satisfy the needs for cost effective improved oil recovery in onshore and offshore remote production locations.
First Time Application of Stand Alone Screens with Sliding Sleeves in the Giant Mangala Field, Rajasthan India
Authors: Chavan Chetan Harish , McKenzie Tim , Wenk Andrew D.G. , Tandon Rohit , Bhat Suniti
Published: March 2015

This paper describes the first time selection and successful application of Sliding Sleeve Sand Screens in the open hole completions of the giant Mangala field situated in the Barmer Basin in Rajasthan, India which holds ~1.2 billion barrels (bbls) of oil in place.

The field is a multilayer reservoir and has waxy viscous crude with in-situ oil viscosity up to 17 cp. The field is being developed with a hot water flood for pressure maintenance and reservoir sweep. Significant production challenges include; an unfavourable mobility ratio, early water cut, sand production and high pour point.

Production well completions with sand screens with sliding sleeves play an important role in the field development, providing a very flexible tool to manage production from individual sand units coupled with open hole sand control. The screens are installed as an open hole completion and swellable element packers provide annular flow control. Intervention costs are kept low, as the field is onshore and the opening / closing of the sliding sleeves are done with relatively cheap onshore well intervention via slickline.

Active reservoir surveillance and management in Mangala field will play a key part in maximising reserves and production rates from the field. Sliding sleeve sand screens are an appropriate technology for the Mangala field oil wells. These screens provide options for downhole water control across the formation thus increasing well life and reducing water handling at surface.

This paper describes the design and implementation of these completions and how the completions provide optimum reservoir management capability for the Mangala field.
Breaking Oil Recovery Limit in Malaysian Thin Oil Rim Reservoirs: Water Injection Optimization
Authors: Chan Keng Seng , Kifli Azmukiff Muhammed , Darman Nasir B.
Published: March 2015

The goal of an oil field development project is to accelerate the hydrocarbon production and maximize the recovery at a lowest cost. For a thin oil rim reservoir with a large gas cap on top and a strong aquifer below, achieving such goal can be very challenging since recovery of both oil and gas shall be maximized. A successful project shall entail plan first to accelerate the oil production maximizing the oil recovery prior to the gas cap blow-down.

The maximum oil recovery factor achievable in thin oil rim reservoirs was evaluated for a Malaysian thin oil rim reservoir. The force balance between the gas cap expansion, aquifer expansion and viscous withdrawal was demonstrated by showing the model simulated water-oil and gas-oil contact movement. The understanding of the force balance progressively guided the field development project team to selectively re-activate some of the idle wells, to selectively place new additional infill horizontal wells, and to plan selective water and gas injection in key reservoir sectors.

In this paper, the concept and strategy of water injection for a subject thin oil rim reservoir was delineated. Placement of a system of water injectors at the selected sector periphery and at the gas oil contact was studied.

Together with optimization of infill well placement and the selected idle well reactivation, this effort showed a potential of improving the current recovery factor from 35% up to 51%, way beyond the maximum theoretical vertical displacement efficiency. In addition, it can be shown that successful water injection can improve productivity of production wells due to increasing near wellbore oil saturation.

Introduction

For thin oil rim reservoirs in Malaysia, the key force balance is between the gas cap and aquifer expansion, and the fluid withdrawal by well production, in addition to the capillary and gravitational forces. The understanding of the force balance in the reservoir will lead towards a better optimization of reservoir oil and gas production, achieving a higher recovery factor, and generating a good investment plan (Ref. 1).

The study in this paper will focus on the Seligi field in Malaysia. It is located offshore Terengganu and was progressively developed starting in 1978 as an oil field. It is a combination of stratigraphic and heterogeneous structural traps (Figure 1). It has a huge regional aquifer and 5 distinctive gas caps (Figure 2) at the time of discovery/development with a significant amount of oil in place (Ref. 2).

Seligi field was developed with the concept of produced gas re-injection at the gas caps. Typically, 75% of the produced gas was re-injected via 15 gas injectors at the 5 gas caps. However, the subject oil rim reservoir pressure has been declining gradually as oil being produced (Figure 3).