bluuebunny/crossref_metadata_2025 huggingface dataset:
The Implementation of Model-Based Predictive Emission Monitoring System for Reducing Fuel Consumption and Emissions Output
Authors: Meziou A. Zak
Published: December 2014

Across the globe, the oil and gas industries continue to face stringent emissions monitoring, reporting and reduction goals which require increased reliability and accuracy of the emission monitoring technology and solution. This paper describes the implementation of a patented, model-based, Predictive Emission Monitoring System (PEMS) as an alternative to the traditional hardware-based solutions. PEMS utilizes powerful analytic models with automatic routines for model and real-time sensor validation while accounting for the effects of process and ambient conditions in order to predict emission values with greater reliability and precision. Such model-based systems provide a regulatory certifiable solution with a lower total cost of ownership, and play a strong role in the optimization of burner/boiler efficiency.

The hardware-based approaches may lack the accuracy, timeliness, consistency and security demanded by today's regulations. On the other hand the proposed software-based emission monitoring application takes readings from the processing plant's existing fuel flow, heat value, and mass density monitoring equipment to calculate emissions. It can also provide feedback to plant operators so they can optimize boiler operations for both energy savings and emissions reductions.
Coiled Tubing Growth and the Benefits of Thinking Small Again
Authors: Stanley Rick , Terry Adrian Robert , Dean Gregory D
Published: December 2014

Coiled tubing has become an integral component of many well service and workover applications and programs. Its development, as we know it today, dates back to the early 1960s. While well services and workover applications still account for approximately 75% of Coiled Tubing (CT) use, technical advancements have increased the utilization of CT in both drilling and completion applications1. In recent years the industry has been trending towards drilling deeper including more highly deviated and horizontal wells. In turn this has also included larger and more complex completions. This trend has challenged the CT service providers to develop larger, more robust and innovative equipment to deploy larger coiled tubing sizes and to support increasingly difficult well bore interventions. It is important that we understand the history behind the initial small CT units (CTUs) and pipe sizes, their limitations and the evolution to the large CT unit (CTU) sizes of today. It is also important that we review some of the coiled tubing related technology advancements (such as friction reducers, small CT motors and stronger pipe development) and relate them as to how they help support the case for using smaller coiled tubing (CT) services in some circumstances. This paper describes why the industry still requires smaller CTUs and pipe sizes along with the benefits they offer today, particularly in offshore applications.

A Small CT unit utilizing smaller CT pipe has recently been developed and deployed on challenging projects in Asia Pacific to provide operators with cost effective methods to maintain wellbore integrity and enhance production. The Small / lightweight CT equipment package is very comparable to a more conventional, larger CTU spread. A Small CT package can consist of a lightweight and small footprint CT unit, a small nitrogen unit, small nitrogen tanks and compact pressure pumping equipment. As an example, for a gaslift type job using Small CT versus conventional CT equipment, the equipment foot print is reduced by 40% and the equipment weight is reduced by 46%. The small foot print and light weight of the Small CTU is especially beneficial in conditions where crane or deck space limitations are challenges.

This paper includes case histories covering the application of this Small CT technology and will review reduced operating costs, logistical support and risk exposure, demonstrating how the technology can be applied to both onshore and offshore environments worldwide. Wells that were once considered plug and abandon candidates due to economic, technical challenges or accessibility may now be candidates for Small CT technology solutions.
Overcoming the CO2 Supply Challenge for CO2 EOR
Authors: Gray L. , Goodyear S.
Published: December 2014

As the major fields which have been the mainstay of global oil production mature, there is a need to apply new technology and recovery techniques to extend field life and maximize economic recovery. As a result, there is growing interest in using CO2 for miscible flooding, where that is appropriate. Much of the current experience of CO2 EOR has been in the US Permian Basin, based on using CO2 sourced from high CO2 content subsurface sources. While significant CO2 EOR potential exists in many basins around the world, application of CO2 EOR is often limited by the availability of CO2 at an acceptable cost. This paper addresses the key issue of CO2 sourcing for CO2 EOR in new basins in which CO2 is the most suitable miscible fluid and the different subsurface conditions encountered with the need for subsurface/surface integration.

The full potential for CO2 EOR to increase recovery factors will only be realised if supply options can be developed for EOR projects in locations that do not have access to an existing CO2 infrastructure. Value chains linking industrial sources of CO2 to appropriate field targets are expected to be the key enabler. Robust technical and non-technical integration across the capture-transport-injection chain is required, to ensure that the potentially competing operational requirements for capture and EOR usage are reconciled, and that commercial and regulatory considerations are addressed. CO2 capture options and a methodology for developing CO2 supply options will be described and illustrated with experience from the development of CO2 value chains for CCS demonstration projects such as Peterhead, Quest and Boundary Dam.
New Acoustic-Telemetry-Operated Tester Valve for Drill-Stem Testing Operation in Deepwater - Brazil PreSalt Case
Authors: Marcançola Fernando , Martin Adam , Zeller Vince
Published: December 2014

Drill Stem Tests (DSTs) in exploratory wells are important for production planning, for identifying the characteristics of oil and gas, and to assess the commercial viability of the entire reservoir. A new generation of downhole test tools has been developed to address the growing challenges of reservoir testing and evaluation in the deep and ultra-deep-water environments now being explored; these new tools maintain safety as paramount and strive for greater testing efficiency in the acquisition of the reservoir information being sought in nearly all evaluation and exploration wells today. There is a growing need to better understand each well in real time as it is being tested, not only concerning the reservoir itself, but also the downhole tool mechanics critical to the testing operation. This knowledge helps to reduce uncertainties of downhole conditions, and also, helps to ensure that operations are being carried out in a safe manner and as planned. With the improvements in operational efficiency, savings in rig time also can be gained.

With the application of acoustic telemetry technology, the capability to acoustically communicate and control downhole tools in real time is achieved. Real-time data can be transmitted to and from the downhole tools, allowing on-demand control of well testing operations. The acquisition of real-time gauge data with the additional capability to actuate a new combination tester and circulating valve provides enhanced control of a DST and can provide the operator with ongoing feedback of tool position and status. This enhances the operators' ability to perform the well test with reduced uncertainties. Extending the real-time acoustic system to tool control provides the operator with additional capabilities. The operator can control downhole tools without using annulus pressure, which is not possible with the traditional DST tool systems operated with annulus pressure that restricts the number of different tools used for a DST due to casing pressure limitations. Acoustic-telemetry-controlled tools are not limited in function or number.

This paper discusses a case history in a deepwater, pre-salt area in Brazil where a new acoustic-telemetry-operated tester valve was used to successfully perform DST testing operations. This paper also discusses the new possibilities that this new tool can bring to well testing.

While the main objectives of a DST are basically the same, this new tool enables downhole well-test tools to advance to a new generation of equipment that is designed to optimize time, streamline decision making, minimize environmental and operational risks; and ultimately, help maintain safety as a priority.
Simulation Study of Hydraulic Fracturing Using Super Critical CO2 in Shale
Authors: Fang C. , Chen W. , Amro M.
Published: December 2014

The history of using fracturing fluid of carbon dioxide is more than three decades. Since literature concerning the application of fracturing with carbon dioxide first have been published in 1982, and utilize carbon dioxide in American shale fracturing have been success in early 1990s. Nowadays the application of fracturing fluid in shale hydraulic fracturing is general slick water, however, carbon dioxide will play an important role in shale hydraulic fracturing in the next 30 years, not only because shale gas production is rising all over the world, but also the water resources is increasingly scarce and greenhouse gas emission is increasing.

Universal Distinct Element Code (UDEC) was used to simulate pressurized cracks and hydraulic fracturing in shale with super critical carbon dioxide in this paper. First part compares the displacements of crack surface with three different fracturing fluids, water, slick water and carbon dioxide, based on assuming uniform fluid pressure, certain elastic medium, Young's modulus, Poisson's ratio, and different size of planar crack. In the second part, the assumption of Young's modulus and Poisson's ratio which reflect shale properties, brittleness and fracability were changed, and fracturing effect with super critical carbon dioxide in different shale are simulated, crack displacement were compared in these assumptions.

The simulation results suggest that viscosity of hydraulic fluid influence formation of hydraulic fractures and super critical carbon dioxide need more volume of fracturing fluid to contribute same crack displacement. Meanwhile, the performance of different shale fracability with super critical carbon dioxide fracturing fluid shows shale fracability index ranges in this model, and to some extent, using carbon dioxide as fracturing fluid have more economic and environmental significance.
Oil spill trajectory simulation for the Saltpond oilfield, Ghana, West Africa
Authors: Korsah Percy Erasmus , Anifowose Babatunde
Published: December 2014

The exploration and production of petroleum resources is not without environmental consequences and these remain an important factor in contemporary global oil industry. As an emerging oil producing nation, very little or nothing is known about the behaviour of Ghana’s sweet light crude in water under varying environmental conditions. This is crucial for an efficient management of accidental spills. Therefore, this study designed a deterministic model for oil spill trajectory simulation using the Saltpond oilfield (Ghana) as study location. The main objectives were to: (a) design a diagnostic GNOME model to configure and generate localised oil spill scenarios; (b) model different oil spill scenarios and weathering profiles for varying environmental conditions e.g. wet/dry seasons, different currents and wind conditions; and (c) Predict the ‘minimum regret’ Splots as a precautionary principle. A combined Eulerian-Lagrangian approach involving a hydrodynamic model containing localised environmental parameters from the Saltpond oilfield was utilised. The General NOAA Operating Modelling Environment (GNOME) based on a C++ programming language was used to execute the analyses. In addition, the ADIOS2 oil weathering tool was used to estimate the oil budget for different spill quantities based on the physical and chemical properties of Ghana’s sweet light crude at Saltpond field. The key findings are: 5000 and 10,000 barrels of spilled oil beached after a minimum of 12 hours in 97% of the scenarios under the influence of winds from the South. Wind speeds leading to beaching were 35.7% for 14 and 16 knots, 14.3% for 17 knots and 7.1% for 15 and 20 knots respectively. Weathering results showed a maximum of 43% of spilled oil evaporated after 116 hours with a minimum and maximum dispersal of 1% and 7% respectively. This study, for the first time, has provided hitherto unavailable analysis and information on oil spill transport forecasting and trajectory simulation for the Saltpond Oilfield in Ghana which environmental managers/engineers would find readily useful in responding to future oil spill disasters. The approach and methodology used in this study could also be adapted for other offshore regions in Ghana and West Africa.
Stand-Alone Wireline Oriented Perforating System Delivers New Production in a Triple Completion Well
Authors: Bou Said M. S. , Nofal S. F. , Channa Z. , Salsman A. D. , Abdel Shakour S. , Assagaf M.
Published: December 2014

In order to meet the production targets set by ADMA-OPCO, more focus is given to inactive strings revival by undertaking quick and economical rigless intervention operations in carefully selected candidates. The candidate described in this case study is one of several old wells that are completed with 3 x 4 ½" tubing strings run side by side in a 12 ¼" borehole and then cemented in place. Some of the wells suffer high water cut causing one or more of the strings to cease production. The plan, after checking the integrity of the tubing, was to shut off the water zone and perforate a new zone using oriented perforating technology to avoid damaging the other 2 healthy strings. The well was completed in the past using an obsolete directional perforating technology.

To shoot in the correct direction a special tool was used to orient the gun away from the other 2 strings before perforating. This tool has a shielded electromagnetic (EM) section that is sensitive to total metal thickness in the range of the measuring device. The gun and the measuring section are run into the well together on wireline and rotated by an electric motor until the gun is pointing in the correct direction. A joint task force between the ADMA-OPCO rigless intervention team and Schlumberger was created to assess the technology application and risks. Several simulations were done in a test jig built to simulate the well configuration both horizontally and vertically to assess the response of the tool. The ADMA-OPCO rigless intervention team was involved in the simulation, design and testing and have approved the operation after all the required tests were completed along with a risk assessment made to mitigate the expected risks. The job was executed successfully using the EM tool and zero phased 2-7/8″ hollow carrier guns, bringing an additional 3000 bbls of production. Confirmation that the job was successful was made by putting electronic gauges in the other two strings to record a communication test done before and after perforation. This is the first time this technique has been used in the Gulf and it has strong potential in similar environments in the area.
Challenging HPCT Scale Removal Operations in High H2S Environment Successfully Completed with Interdisciplinary Job Design and Execution
Authors: Green T. A. , Leal Jairo A. , Ginest N. H. , Al-Bu Ali M. S. , Vielma J. R. , Chacon A.
Published: December 2014

The carbonate gas producing zones of the Ghawar field have been impacted by extensive FeS scale deposition, reducing overall gas production and significantly increasing risks of well interventions. Previous remediation included the use of workover rigs which can be costly due to time required for workover and lost production. H2S levels (2-7%) found in the reservoir also contribute to higher costs and risks when using workover rigs.

Different chemical solutions have been utilized in similar cases and also considered for these wells, but the FeS could not be 100% dissolved with either HCl, DPTA, EDTA, GLDA blends. These chemical blends generate large amounts of H2S in addition to the already existing high levels of H2S in the formation gas. Additionally, the completion tubulars and CT were adversely affected by chemical reaction and corrosion. This poses a safety concern having large amounts of H2S in returns at surface along with potential chemical corrosion. Therefore, the safest and most economical method was to devise an effective mechanical descaling solution with CT.

This paper will discuss two case histories where mechanical descaling utilizing CT was applied. Each well had major challenges that included low reservoir pressure, increased reservoir temperature, scale with high specific gravity (3.7 to 4.3), and in the second case, horizontal open-hole sections. The low reservoir pressure required isolation methods to allow for returns to circulate out the heavy scale and to minimize fluid losses to the formation.

Following mechanical descaling with CT, the final challenge discussed in the paper is bringing the well back to maximum gas production using HPCT cleanout optimization and HPCT stimulation techniques.
Development of Streamline Simulation for Miscible Recovery Process and its Application in an Onshore Oil Field-Abu Dhabi
Authors: Bratvedt Frode , Yi Tongchun , Shaker Ashraf , Takahashi Masahiro , Didanloo Ali , Bouaouaja Mohamed , Bassiouni Mahmoud , Al Basry Ali H. , El Mahdi Ahmad
Published: December 2014

This paper describes the implementation of the solvent model in streamline simulation and its application to WAG injection optimization for a producing field. The solvent model was implemented as an extension to the 3-component black oil model, with solvent as an additional component, to model miscible displacement process. The relative permeabilities and fluid properties of the oil and gas phases are modified based on the fraction of the solvent component, the reservoir pressure and the Todd-Longstaff mixing-parameter (i.e. an empirical treatment of the effects of physical dispersion between miscible components).

The solvent model was applied to a Middle Eastern oilfield, which is currently under development using a miscible WAG process. PVT analysis has been done to prepare the properties for the reservoir gas and the injection solvent. Streamline simulation models with and without solvent model were run to compare the results with a reference finite difference compositional reservoir simulator and the effect of miscibility has been validated.

Results of streamline simulation models with and without solvent model were compared against a reference finite difference reservoir simulator. The comparison shows the streamline simulation model with solvent model has much better agreement with the reference finite difference compositional reservoir simulator which shows that the miscible displacement process is properly simulated in the streamline simulation model with solvent model.

The solvent model presented in this paper advances streamline simulation technology, combining the intuitive and unique properties of streamlines and the capability of simulating miscible recovery mechanism. It allows simulating both immiscible and miscible displacement within the same simulation. The solvent model considers the effects of miscibility by considering relative permeabilities and fluid properties adjustments based on pressure and solvent concentration. The technology will help effective simulation of miscible recovery process, assist optimum solvent allocation and improve unified sweep.
Jasmine Field, Gulf of Thailand: How a 7 MMbbl Oil Field Produced 50 MMbbls and is Still Producing
Authors: Oglesby C. A. , Boardman D. W. , Edwards M. , Saifuddin F. , Platt C. , Limniyakul T. , Watcharanantakul R. , Henneberg H. P. , Tabmanee P. , Maneejan R. , McClure J. , Reverdito D , Ionnikoff Y.
Published: December 2014

The Jasmine Field began production in 2005 with initial estimated recoverable reserves of 7 MMbbls. Appraisal continued after the initial "A" platform commenced operation resulting in significant reserve growth that allowed for the installation of four additional production platforms (B, B1, C and D) and one remote platform, Ban Yen "A", which began production in 2008. The Jasmine (and Ban Yen) Field was developed via deviated wellbores from the various platforms and was considered fully developed by late 2009. Oil production declined rapidly, accompanied by rapidly increasing water cut; leading to the perception of a short economic field life (in 2009 the end of field life was expected during 2012).

Since 2009, Mubadala Petroleum has been engaged in an active infill campaign, drilling 44 infill wells and 3 delineation wells. Delivery of this successful infill programme resulted from: Integrated study of two volumetrically significant reservoirs; the 680 and 50-sands (key targets for infill programme);Active reservoir management, increased data acquisition and reservoir surveillance activities;Utilisation of horizontal wells (usually geo-steered) to improve recovery (20 wells since 2009);Expansion of the facilities to accommodate additional well slots and water handling;Recent use of isolatable multi-zone completions to mitigate water coning/cusping.

The success of this endeavor is such that a 50 MMbbls production milestone was passed in November 2013 and end of field life continues to increase through the use of improved engineering, science and technology.
Formation Evaluation in Gas-Bearing Reservoirs Drilled with Na/K Formate WBM, Using LWD Time-Lapse Data Acquisition
Authors: Fakolujo Kehinde M. , Al-Belowi Ali , Gzara Kais , Onuigbo Oluchukwu L. , Pasaribu Ihsan T.
Published: December 2014

The introduction of formate-based drilling muds successfully addressed drilling challenges related to barite-weighted muds. The muds exhibited peculiar petrophysical properties that adversely affected log interpretation. First, the mud present inside the borehole and surrounding the tool required different environmental corrections; secondly invading mud-filtrate present inside the formation was difficult to account for. Because of the higher density, lower hydrogen index, and high gamma-ray readings associated with Na/K formate-based drilling fluids, for example, petrophysical analysis typically resulted in inaccurate mineralogy and pessimistic porosity and permeability estimates. Such estimates were also strongly dependent on the extent of invasion by the mud.

Two new approaches were developed to address these long-standing challenges in gas-bearing siliciclastic and carbonate sequences. Logging-while-drilling (LWD) time-lapse data acquisition makes it possible to track changes in log measurements between a first (drill) pass and a second (wipe) pass as mud filtrate invades the formation. In a first approach, these changes reflect the contrast in petrophysical properties between the mud filtrate and the displaced native formation fluids, and can be used to estimate the unknown petrophysical properties of such mud filtrate. In a second, geometric approach, the different measurements are considered to represent different axes in measurement space, and then the axes are rotated to reduce the number of rotated measurements affected by invasion to just one. This measurement is then discarded, and the remaining rotated measurements are used.

In all, up to six different petrophysical models from two different wells were compared. The results indicate a step change in petrophysical analysis in case of Na/K formate-based drilling fluids. They demonstrate how it is possible to build a robust but remarkably simple petrophysical model using only rotated nuclear measurements, with all of the following characteristics. The model is extremely stable as compared to more complex models. It requires neither knowledge of the Na/K formate mud-filtrate characteristics, nor knowledge of its volume. It does not require resistivity input, but consistently reproduces similar saturations when compared with models using resistivity as input. Data from the drill- and the wipe-pass produced identical results, independent of formation invasion.
Avoiding Surface Collision and Drilling a Smooth Well Using Gyro-While-Drilling in Offshore Abu Dhabi/UAE
Authors: Day Tim , Hormozy Behzad , Khaled Al-Awadhi Farhaad , Al-Husseiny Afifi Hassan , Abdul Karim Hassan , Abu Hasira Mohamed , Al-Ameri Fahad
Published: December 2014

Drilling wells from offshore platforms is always a challenge because of the need to eliminate potential collision issues caused by the relatively close spacing of wellheads. On a platform offshore Abu Dhabi, the spacing of the wells is 7.4 ft center-to-center and less than 5 ft wall-to-wall. There are nine slots on the tower, with five slots already used. Based on the required kickoff azimuth, the most logical slot for a high- profile deep and high temperature well was slot 9 (on the corner of the template) to reduce the risk of a well-to-well collision. However, using slot 9 would make it very challenging and risky to use slot 3 in the future.

A detailed risk assessment was conducted, and the following risks were identified: 1. the motor producing an unknown amount of reactive torque while kicking off, could lead to a departure of the well from the plan and a collision with other wells or to block the empty slots. 2. Excessive dogleg at a shallow depth would incur high torque and drag in deeper sections, thus increasing the risk of string washout or twistoff and excessive casing wear. Also putting a higher loading on the top drive to drill the deeper sections. 3. Rig time would be taken for running the single-shot gyro. 4. As the circulation would have to be stopped to take the gyro single shot, there would be risk of hole packoff and stuck pipe. 5. There would be a long distance from the bit to the survey point if the single-shot gyro were run above Measurement-While-Drilling (MWD) tools, causing a "late reaction" to any deviation changes.

After discussion, and a detailed cost / benefit analysis and risk assessment, it was decided to use a Gyro-While-Drilling (GWD) service as this would remove or significantly reduce the identified risks. This was the first usage of this service in the UAE for ADNOC companies (ADMA, ZADCO, ADCO), and the results were excellent. The well was kicked off in the correct direction from the start. There were no violations of the anti-collision rules to offset wells or empty slots. The well was steered away from slot 9, leaving it to be used for future wells. There was no reduction in the drilling parameters used to drill this 26″ hole section. There were no hole packoffs or stuck-pipe incidents, and the service saved at least 8 hours of rig time. Tight communication ensured all personnel involved had timely access to required information, which increased the confidence in decisions to drill ahead.
Global Anisotropic Pre Stack Depth Migration (PSDM) Velocity Modelling to Mitigate Structural Heterogeneity and Eenhance Imaging
Authors: Thakur Ram Kumar , Zhou Fugen , Chakraborty Kalyan , Mike Q Ye , Al-Kandari Abdullah
Published: December 2014

Seismic imaging in time domain is extremely difficult because of the insufficient illumination at the crest of South Fuwaris Humma-ARQ structure with 32 (thirty two) 2D seismic lines which were acquired in two vintages 1978 with 24 fold and 1996 with 80 fold. Due to large near surface lateral velocity variations and severe ray distortion by low velocity layers in surface seismic data, first-arrival turning ray tomography in a 3D sense proved to be useful during the initial time domain processing for deriving statics corrections to minimize these distortions and mitigate different causes of statics problems.

A key element of the reprocessing objectives was to generate an image in depth using prestack migration that takes near-surface velocity model derived from the turning ray tomography into account. For this purpose, the near-surface velocity model was used as the shallow layer of the depth initial velocity model, with the travel time effects calculated directly by ray tracing rather than by statics corrections. The deeper parts of the initial velocity model were derived from 3D smoothed velocity model that was coming from prestack time migration velocities for the re-processed 2D lines.

Two iterations of global isotropic tomographic update for velocity model were computed prior to reach the final anisotropic velocity model in depth domain. Delta and epsilon (anisotropic parameters) were manually picked and then a tomographic update of the anisotropic velocity model and the anisotropic parameter (delta) took place. Special effort was taken to minimize the mistie at well locations at major seismic markers and at the intersection points of the dense intersecting 2D lines with interactive interpretation and processing technique.

This paper presents an innovative Global Anisotropic Pre Stack Depth Migration (PSDM) velocity modelling technique to reduce structural uncertainties which enabled to drill exploratory wells in ARQ field.
Next Generation Broadband Land Acquisition
Authors: Baeten Guido , Hwang Jay , Walk Wim
Published: December 2014

The acquisition of broadband full azimuth surveys in a desert environment requires the application of several new technologies. These technologies can be divided in three main fields: the seismic receiver, the seismic source and the processing algorithms. We will discuss these new technologies, and show that the developments towards high channel counts and low frequencies are intimately related. Hence, an integrated approach is required to make optimum use of new emerging technologies. We also show some applications of the technology, demonstrating the value that these novel acquisition techniques can provide.

Source - Desert surveys almost exclusively use Vibroseis as a source. Over the last two years, the use of low frequencies in onshore seismic acquisition and processing has become more and more a routine practice. However, the emission of low frequencies by seismic vibrators is far from trivial and required a number of new technological developments and field tests. We will discuss the developments in vibrator technology, the limitations that are still in existence today and possible future developments.

Receiver - Current developments in land seismic acquisition show a trend towards higher channel counts and increased bandwidth. In addition, the increase in use of single sensors provides potential for acquiring higher resolution data, and improved signal preservation at the higher frequencies.

For broadband desert surveys, to significantly improve data fidelity, data sampling needs to be much improved by much increasing the channel count and including very low frequencies down to 1Hz. Shell is investing in the development of broad band land sensors that records to very low frequencies (< 1Hz) and are cost-effectively scalable to 1 million channels. Single, light weighted, sensor systems will be much cheaper and faster to deploy, with less staff and lower HSE footprint. We will describe the status and report on recent field trial in the Middle East.

Both the full azimuth aspect of the surveys and the low frequency content require the application of dedicated processing algorithms. These processes vary from a geophone amplitude- and phase correction early in the processing chain, to Full Waveform Inversion and processing techniques that account for azimuthal variations at later stages in the processing. Applications of broadband full azimuth technologies will be shown, demonstrating the benefits that a bandwidth extension can provide to the seismic data in terms of increased resolution and structural definition.
Application of CSS to Develop a Thick Heavy Oil Field in South Oman
Authors: Al-Manhali M. , AL-Rawahi M. , Al-Hinai S. , Alwazeer A. , Al-Shaqsi K. , Brissenden S. J.
Published: December 2014

The "A" East is a heavy oil reservoir in the south of Oman. It was discovered in 1978. The reservoir is sandstone with a 200m thick oil column. Oil sampled from the field showed high oil viscosity and was considered to be problematic for primary production. In 2008, the field development plan proposed to develop the field thermally, starting with cyclic steam stimulation and followed by steamflood. CSS trials (2008 – 2010) were carried out in three wells using temporary facilities to evaluate the injectivity and productivity of the wells. This helped to identify the surface and subsurface challenges in the field and resulted in modifications to the full-field CSS deployment.

During the drilling campaign (2010-2012), a crestal well was cored and oil viscosity data was acquired. The results showed oil viscosity varies from 400 to 400,000 cp (at 55°C) from top to bottom of the reservoir. Production testing, using portable tanks proved the cold production concept. 32 out of 81 wells were selected to be initially cold produced by PCP before converting them later to CSS. On 9th March 2013 cold production from crestal wells started, which provided early production. One of the subsurface concerns identified during the "A" East field development study was the effect of the high initial reservoir pressure (~11,500kPa) on steam injection efficiency. Cold production helped to lower the reservoir pressure. Recently acquired pressure data indicate that the reservoir pressure fell to around 4000 kPa in the crestal area and to 6000 – 10500 kPa on the flanks of the accumulation.

"A" East steam injection started on the 2nd of March 2014. Initial injection data suggest that higher injection rates were achieved due to the lower reservoir pressure from cold production. The current plan is to ramp up steam injection and increase the number of CSS wells through converting more of the cold production wells to CSS. CSS operations will then be followed by pattern type steamflood (inverted 9 spot) once the reservoir pressure is depleted and connectivity is established between the wells.
Heavy Oil and Relative Permeability in Laboratory, Simulations and Production; Is There A Link?
Authors: Berg Eirik Asbjørn , Bjørlykke Ole Petter
Published: December 2014

One important challenge working in heavy oil field development is to present a set of production profiles representing low, base and high production without being overly optimistic or pessimistic. The paper give examples on how various methods of assessing the uncertainty in the relative permeability curve shapes changes the view on project uncertainty. Heavy oil laboratory relative permeability experiments face many well-known challenges. The core data is usually unconsolidated with very high permeability. This combined with high viscosity usually leads to unfavourable laboratory conditions like in example capillary end effects and viscous fingering. Typical core issues are fractures, laminations, loose sand, issues with use of multiple core plugs and very low pressure differential at initiation of the experiment. In addition there is always a discussion about reservoir wettability and core history including impact of drilling operations, drilling mud and core depressurization. The total effect is that the laboratory data is often seen as highly unreliable. The challenges are usually solved by using either light oil or by using steady state together with unsteady state experiments. Weaknesses and strength of the steady state method is addressed. Discussion of the alternative methods that is available is given with examples. Can light oil really be used instead of heavy oil given the large compositional differences? What could the impact of asphaltene content be? Examples are given of some typically laboratory effects. A brief discussion is given regarding possible reasons for differences between light and heavy oil behaviour. A benchmark of relative permeability experience from 50 heavy oil fields is presented. The benchmarking methodology is given and explained. Strength and weaknesses of the method is discussed. Actual field data is shown. Examples of relative permeability data used in simulation models are shown. Impact of grid size and properties on relative permeability is shown. Use of rock curves and alternative curve fit methods is presented with weakness and strengths.
Oil Recovery for Heavy Oil by Displacing Agent/Foam Assisted Steam Flooding: Laboratory Experiments, Numerical Simulations and Field Performances
Authors: Liu Hao , Hou Jian , Wu Guanghuan , Wei Tao , Wang Daigang , Wang Chuanfei
Published: December 2014

Shengli oilfield, the third largest oilfield in China, has abundant ordinary heavy oil resource and steam flooding is one of the most common used recovery methods for it. However, several obstacles have been encountered by conventional steam flooding in those blocks: (1) The significant heterogeneity of formation makes severe steam override and steam channeling. (2) The deposition of reservoir is deep, leading to severe heat-loss. (3) The distribution of remaining oil after water flooding is dispersing.

Laboratory experiments, numerical simulations and field performances of the displacing agent/foam assisted steam flooding pilot are described in this paper. It is an enhanced oil recovery process uses an injectant containing steam and additives consist of oil displacing agent, foam agent and nitrogen gas.

Laboratory experiments indicate that oil recovery factor for displacing agent/foam assisted steam flooding in porous media is much larger than that of steam flooding. Numerical simulation results present that the enriched remaining oil in lower layers caused by steam overlay is effectively produced by using the additives compared with using steam individually.

Displacing agent/foam assisted steam flooding conducted in two well groups at Gudao block is the first field test in Shengli oilfied. The smaller well group consists of one injection well and nine production wells, while the bigger group consists of four injection wells and twenty-one production wells. The total water cut for the smaller well group has decreased from 83.8% to the lowest of 79.4% and daily oil production has been improved from 49.0t to 62.4t. The total water cut for the bigger well group has decreased from 91.0% to 85.7% and daily oil production has been increased from 70.1t to 113.0t. Therefore, displacing agent/foam assisted steam flooding is expected to be a more efficient method than conventional steam flooding to improve oil recovery in Shengli oilfield.
Preparing a Challenging Fractured Carbonate Reservoir with Heavy oil for EOR Application
Authors: Al-Rashdi Y. S. , AL Kindi A. , AL Bulushi S. , Azri N. , te Riele P. M.
Published: December 2014

Heavy oil fields with complex geology present a great challenge for a commercial development. The field described in the paper is a heterogeneous, sparsely fractured carbonate field with oil viscosity of 5,000–10,000 cP. Initial production test proved that the field cannot be commercially developed using conventional development primary and secondary recovery technologies.

A number of EOR recovery processes have been reviewed for applicability to this field. A fit for purpose uncertainty analysis on key parameters lead to the conclusion that thermal recovery methods are not technically feasible mainly due to steam confimenent issues. A solvent based EOR development scheme was identified as a potential recovery route for such reservoir environment. A feasibility study was conducted to determine whether solvent injection is attractive under a number of realistic subsurface realizations and completion strategies. This study resulted in a number of activities to derisk uncertainties and come to quality decisions towards a solvent development.

Series of field tests have been conducted to mitigate some of the risks associated with the solvent development. Firstly, given the low permeability and low oil mobility, the presence of mobile water is essential in order to inject the solvent and contact the oil with the solvent. Water injection tests were carried out to demonstrate the presence of mobile water in all different reservoir zones and confirmed matrix injectivity is possible. A next step is to utilize the mobile water to inject a solvent into the reservoir and contact the oil accordingly for which a solvent test is planned using a mixture of xylene and diesel. A xylene-diesel mixture was selected as this showed in laboratory tests first contact miscibile with the field crude oil and is readily available for field application. The objectives of this single well injection test are to 1) confirm and quantify solvent injectivity, 2) prove heavy oil mobilization through solvent EOR methods from carbonate reservoir settings and 3) to determine near wellbore sweep efficiency of solvents injected into long horizontal wells. If successful a multi well continuous injection trial will be designed and executed.

This paper describes the design and analysis of the single well solvent injection test for this heavy oil carbonate field. It also describes the experimental lab work conducted to confirm xylene-diesel compatibility with the field crude oil and its suitability for application in a solvent EOR development derisking.
Fast Yet Clean Downhole Heavy Oil Samples From Wireline Formation Tester Using Selective Slug Sampling Technique
Authors: Tran Huy N. , Tran Lam V. , Nguyen Thang V. , Tran Ninh D. , Tran Dinh V. , Hardikar Nikhil P. , Coskun Sefer B.
Published: December 2014

This paper discusses the application of selective slug sampling using the wireline formation tester – RCX* (Reservoir Characterization eXplorer), in a clastic heavy oil reservoir and its significance to fluid characterization. The low mobility ratio between the reservoir fluid and water-based mud filtrate results in a long cleanup time to obtain samples with an acceptable level of contamination. Tool sticking and wellbore stability issues add to the challenges in open-hole fluid characterization and testing. Increasing the flow rate to reduce cleanup time does not help mostly due to formation of an emulsion between the viscous oil and the mud filtrate. The emulsion is hard to disperse, leading to a contaminated sample. A higher flow rate results in sanding and loss of seal.

In selective slug sampling, phase segregation is achieved by lowering and optimizing the flow rate, reducing the pressure drawdown that curtails emulsion formation and movement of grains thus increasing the sealing efficiency. The segregated oil slugs can be selectively collected in sample tanks multiple times downhole. Even a water cut of 60 to 70% is sufficient to collect high-quality samples, which is a significant improvement in sampling time compared to conventional fluid sampling, where 10% or less water cut is required.

The technique was applied in an unconsolidated clastic heavy oil reservoir in Vietnam. Four 14- to 22-°API single-phase oil samples were collected in two hours each. Laboratory results indicate less than 10% contamination; water cut being 50 to 75% at the time of the sampling. It was the first time that successful heavy oil samples were collected from these layers.

Fluid sampling is critical to identifying compositional variation of reservoir fluids along the depth, resulting in appropriate sampling strategy and eventually correct fluid characterization. Sampling in unconsolidated heavy oil reservoirs is improved using the selective slug sampling technique, making it possible to secure fast, yet high-quality samples, aiding fluid property characterization.
Development Of The Mexican Field - Samaria Neogene
Authors: Flores de Dios Mosqueda Tania , Isidro Torres Ezequiel Arturo , Arteaga Cardona Marcela , Tapia Garcia Carlos Fernando , Silva Lopez Pedro
Published: December 2014

Due to the success and experience obtained in the Samaria Neogene field pilot test, it was decided to exploit the field by cycling steam stimulation.

The development of the field has been carried out in three phases. The first phase, 48 wells were drilled with 400 meters spacing. The positive results of the first phase encouragement the development of the second and third phases, they consisted in 43 and 33 infill wells, with 200 and 150 meters spacing respectively.

In the first cycles, the injection pressure was very high, even in the wells that were produced for 6 months with Sucker Rod Pump (up to 2,400 psi in the deepest wells). In the second cycles there were no high injection pressures since the well surroundings were depressurized by the first cycle. In the second cycles the injection pressure drop between 50 to 400 psi, achieving a very good steam admission by the wells in the second and third cycles.

As a result of the decrease in the well spacing, the wells close to the injection wells began to show a heat increase in the produced fluids, for example, in two wells with less than 50 meters of spacing between them, during the injection of one, the other rase the temperature from 60°C to 110°C. This behavior has been very benefical for the project because reduces the viscosity not only in the injection well if not also in some of the nearby wells, resulting in an increased production in both wells. In most cases, when one of the neighboring wells is producing from the same sands, also there is steam channeling. If this channeling will be controlled, it would exist the possibility of moving to a continuous steam injection.

This paper will present how the steam injection has been successful despite different conditions taken in the pilot test.