bluuebunny/crossref_metadata_2025 huggingface dataset:
Case Studies of Using Far and Ultra-Far Seismic Data in Deep-Water Nigeria Erha North Field: Beauty and the Beast
Authors: Zhang Mei , Lee J.J. , Xu Shiyu , Molyneux Joe , Garfield Tim , Lovell Richard , Jones Stephen , Wildermuth Eric , Lazaratos Spyros , Bauer Steve
Published: May 2016

This paper highlights the complexity and challenges associated with deep-water exploration and development in Nigeria. The Erha North field Reservoir-300 was discovered using the block-wide 2000 seismic survey. A shallow channel severely attenuated the seismic image at the reservoir level. A new 2005 seismic survey was shot perpendicular to the shallow channel and improved the imagibility of the reservoirs by undershooting the shallow channel. ExxonMobil's Pre-migration Spectral Shaping (EM_PreSS) technique further enhanced the data quality. The EM_PreSS ultra-far 38–48° angle stack provided the best well tie in the Erha North Phase I development area. The significantly improved seismic data quality greatly increased interpretation confidence and impacted the business decision to not drill appraisal well Erha Far-East (EFE) and instead to drill the exploration well Erha North-East (ENE).

The Erha NE prospect is located 7 km away from the center of the Erha North field, with the primary target in Reservoir-300. The seismic response at the up-dip of the prospect is similar to the hydrocarbon response observed at the Erha North field, but lacks conformance to structure - an expected DHI element. The original hole (OH) targeted an up-dip location and encountered multiple gas and oil sands, in both primary and secondary reservoirs. However, the primary target Reservoir-300 was penetrated with two separated thin gas-on-oil sands. No water sand was penetrated. A determination was made that such highly compartmentalized reservoir could not be developed economically.

Down-dip from the Erha NE original hole discovery, a strong low-impedance amplitude anomaly was observed on the ultra-far (38–48°) angle stack. No other angle stack showed a similar strong low-impedance response and no other DHI attributes were observed. This amplitude response was neither similar to other known hydrocarbon responses nor to known water leg responses. Geophysical modeling results could not rule out the possibility of down-dip hydrocarbon presence by using reasonable rock properties assumptions. Given the high resource uncertainty, the operator determined it would be beneficial to test the down-dip location before Phase II development starts. The down-dip side-track (ST) well was drilled and penetrated a thick clean water-bearing sand. Post- drill modeling suggested that abnormally high anisotropy in the sand could be the cause of the ultra-far low impedance amplitude anomaly.
The Application of the Technology of Space Grid Variable Velocity Mapping in the Study of Superdeep Microstructure: A Case in the Tazhong No. 1 Gasfield of Tarim Basin
Authors: Zujun Wang , Dong Lv , Xiongfei Wang , Tianye Wang , Haiqing Lv , Jing Zhao , Xiangzhou Zeng , Zhenzhou Li
Published: May 2016

Block TZ62 of the No. 1 gas field is located in the eastern section of large reef of oil-gas reservoirs in slope break belt of central Tarim Middle-Late Ordovician. Reservoirs (average buried depth?5000 m)on the longitudinal growth developed in a range of 150 meters away from the carbonate rock roof. On the horizontally growth, reservoirs was quasi-layered and contiguous. Currently, the main technical bottleneck of development to increase reserves and production is how to reliably implement microstructures by means of effective variable velocity mapping.

This paper focuses on exploring a method of variable velocity mapping in super deep microstructure and its application on the TZ62 block.

The technology of space grid variable velocity mapping includes quality evaluation of basic data-speed factor analysis-space grid velocity modeling and quality control, etc. At present, due to the collection and processing problems, there are errors, whether from the seismic stacking velocity or logging speed variable velocity mapping. Among the influencing factors, T0-layer and drilling-stratification are more reliable than stacking velocity and logging speed. Based on the analysis on target horizon of block TZ62, by fitting the Three-Dimensional relationship of velocity and T0, we use the variation function of space grid to build the velocity model.

Through the blind Shaft check and application analysis control the quality of velocity model and establish accurate velocity model. According to the time-depth conversion we get reliable fine structure that is suitable for block TZ62. At the same time we get three aspects of the effection:Blind Shaft error is significantly reduced (structure error decreased to within10m from 15~80m),Structural map is more consistent with T0 map in the trend and the microstructure is more accurate,Microstructure and drilling is more matching, structural high place has high gas-oil ratio, oil-gas and water in reservoir distribute whole by the microstructure control.
Innovative Subsurface and Surface Optimisation of Well Placement in Stacked Heavy Oil and Light Oil Pools: A Case Study
Authors: Ruifeng Wang , Qizhi Huang , Xiaoling Yi
Published: May 2016

This paper illustrates innovative application of integrated subsurface and surface optimization of well placement in stacked heavy and light oil reservoirs in M field, Sudan. Upper B reservoir is massive bottom water heavy oil reservoir with burial depth of 700 m. Well productivity was low, 200 to 300 BOPD under CHOPS, resulting in denser well spacing and extensive deployment of flowlines, de-sanding equipment etc., often forcing vertical infill wells drilled as directional wells due to footprints limitation. Lower AG reservoir is stratified light oil and gas reservoir with burial depth of 1500–2200 m, overlapped with above B reservoir to some extent. The operator intended to drill infill wells to grow production, whereas two major well placement challenges are confronted:Integration of facilities and subsurface proposed well locations to reduce drilling costs;Integration of lower AG and upper B reservoirs to maximize recovery;

Well placement strategy has been optimized by following approaches:firstly propose infill well locations based on history matching and scenarios screening; secondly input well locations into facilities maps and identify footprint contradiction; thirdly revise well locations to be compatible with facilities and input back into simulation to justify cumulative oil loss within reasonable range;combine best locations in B and AG reservoirs and directionally deepen into AG reservoir to reduce unnecessary vertical wells in AG reservoir.

Altogether 21 optimized well locations were put forward, totally avoiding 5 footprint-limited directional drilling and reducing 3 vertical wells in AG reservoir by directionally deepening into AG reservoir. Drilling costs were greatly saved and speed up field production growth process during 2010–2011.

Conclusions drawn from successful well placement optimization were:subsurface and surface optimization greatly contributed to drilling cost saving;stacked AG and B reservoir optimization contributed to cost-effective development.
Application of U-Shaped Wells Technologies for Efficient Stimulation of CBM
Authors: Zhang Y. , Zhang G.Q. , Sun F.J. , Bao Q.Y.
Published: May 2016

Coal bed methane (CBM) development in China, especially in both Qin-shui Basin and East Ordos Basin has started at a large scale. There are more than 8500 CBM wells drilled in these two basins and most of which are stimulated with induced hydraulic fracturing and multi-lateral horizontal well technology. However, some of the CBM vertical wells are low productions due to the factors of geology, drilling or producing, while some of the horizontal wells have an appreciate production in the early stage but later drop down to a very low level dramatically due to the wall collapse. Thus, a new technology, namely U-shaped well technology, is researched and applied on site in Qinshui basin for enhancing the average gas productions of CBM wells.

An optimum scheme of drilling and completion of the U-shaped well is presented based on the comparison of the price, risk and feasibility of three different schemes in this paper and used as the pilot program. In order to decrease the comprehensive cost and period of the well, such factors as the access to fuel, water and land, the environmental regulations, i.e., water disposal, mud and drilling waste disposal, and so on, should be taken into account while choosing the well site. The reservoir characteristics and physical parameters, the upper formation lithology and the technology requirements of drilling, cementing and completion should be researched in detail before doing the well design which is the basis of the success of the U-shaped well. Besides, drilling along the coal seams and connecting to the vertical well are two key steps in yielding a successful U-shaped well, therefore, it is important to monitor and adjust the well path in time based on the logging response characteristics, measurement parameters of EMWD, and the drilling and mud logging parameters. With the slotted screen completion in the horizontal well, the U-shaped well can still provide a good flow path for the water and gas even though there is a wall collapse in the horizontal well while producing. In addition, the well bores can also be cleaned up by injecting water form the vertical well and circulating out of the horizontal well when the slotted screen is block by the coal dusts. As a result, the U-shaped well technology can solve such problems as production decreasing and cycle shortening of the multilateral horizontal wells due to the wall collapse while producing.

The daily gas production of the pilot well being in production for only 160 days and in control of the casing pressure kept at 0.7–0.8MPa to produce the gas in accordance with the producing rules of CBM wells has exceeded 2000m3/d. It is still rising gradually and would come up to about 8000 to 10000m3/d in a year's production according to the numerical simulation results which exhibits the U-shaped well a promising application prospect.
New Advances in Interwell Seismic and Electromagnetic Imaging
Authors: Nalonnil A. , Zhang P. , Marion B.
Published: May 2016

Crosswell imaging as a concept and measurement technique for the oilfield has been maturing over the past two decades. As part of this development, both the seismic and electromagnetic versions of the measurement have seen recent advances that have allowed the technologies to answer more complex imaging requirements in the industry today. This paper features case studies which focus on the areas in which the methods have advanced, specifically; downhole seismic source, frequency attenuation tomography and indicator probability imaging.

Introduction

Crosswell Seismic Imaging

Crosswell seismic images the interwell space with an improved vertical resolution of up to 5–10 times higher than surface seismic data. Both direct and reflected wavefields are processed to provide a detailed image of the reservoir. By using higher frequency sources that are deployed alongside the reservoir interval, crosswell seismic surveying generates high vertical resolution reflection images with resolution on the order of 1–3 m. This is due to the high bandwidth of the transmitters used during acquisition with upper frequencies ranging from 800Hz to 2 kHz (depending on the transmitter used and imaging objective).

Since seismic velocity is very sensitive to pressure, temperature and saturation changes caused by the injection of CO2, gas, and steam, crosswell seismic provides valuable information for monitoring injection performance and efficiency as well as reservoir characterization. Crosswell seismic can reliably detect compressional wave velocity changes as small as 1–3%. (Lazaratos et al., 1997) Additionally, since the migrated reflection section provides a high-resolution image of the structure between wells, it helps in answering key questions about the geologic causes of the observed injection performance and fluid flow.
By-Pass Pigging - A 'Simple' Technology with Significant Business Impact
Authors: Entaban Asun , Ismail Ajemi , Jambari Mahmud , Ting Peter , Amin Khalid Mohamad , Ping Chow Chee , Zou Sean , van Spronsen Gert
Published: May 2016

Bypass pigs are similar to normal pigs but have bypass ports to allow for a certain amount of fluid flow through. The bypass flow can "smooth out" the liquid surge. As for non-bypass pigging, all materials present in the pipeline before pig launch will be "pigged" out during the pig passage and nothing will "leak" backward through the bypass ports. Compared to non-bypass pigging, the use of bypass pigging can significantly reduce the production deferment as a result of pigging, capacity requirements for the slug catcher or separator, and the cost of wax inhibitors and risk of wax maintanence pigging. Bypass pigging has been around for many years but simply not been used enough, particularly its potential in handling the pigging slug and reducing production defermerment. This paper presents a case history of a recent successful application in Malaysia. Application of bypass pigging in the trunkline system of Malaysia LNG (MLNG) resulted in very significant production benefits, at virtually zero cost.

Background

Over the years, regular pigging (non-bypass) has been widely used in the industry to clean up pipelines (removal of debris and liquid holdup/slug), and sometimes to apply corrosion inhibitors. However, the liquid and debris volumes generated from the regular pigging operations, under normal production rates, will arrive at the receiving facilities within a short time period and may overwhelm the liquid/solid handling capabilities of the receiving facilities (slug catcher, separator, …), and bring gas starvation risks and even tripping risks in downstream facilities. To mitigate these risks, production levels are reduced during pigging operation.

Applying bypass ports will slow down the pig travel speed and allow debris or liquid surge to travel faster than the pig. Just as with non-bypass pigging, all material present in the line before pig launch will be "pigged" out and nothing will "leak" backwards through the bypass ports because pressure behind the pig is always higher than pressure in front of the pig. The bypass flow can "smooth out" the liquid surge (Figure 1) and transport the solid debris as slurry, and wet the top of the line with the liquid (corrosion inhibitor). By applying bypass pigging, production deferment is reduced or avoided.
Successful Application of System Optimisation Technology to Gas Production in a Complex Onshore Gas Field in China
Authors: Xinggang Han , Hui Wang , Pengxin Feng , Wenlong Xu , Xiaorong Wang , Haibin Ma , McBride Steve
Published: May 2016

The gathering system in the Sulige gas field is characterized by "simultaneous metering of gas with liquids" and by "multiple inter-connections between wells". With the large scale expansion of the gas field, the gathering and transportation system has become so complex that it is increasingly difficult to optimize the production of each well or gas source in an integrated manner and simultaneously eliminate pressure bottlenecks in the network. Traditional optimization methods can handle simulations and process calculations for single wells or small local networks, but cannot adequately address the overall system performance as a whole.

Consequently, integrated optimization technology has been introduced in the Sulige Gas Field. A compositional model of the entire gas field has been constructed of individual production components, and via comparison of simulation results and measured data, the model has been accurately tuned. Based on the calculated results of the tuned model, several conclusions have been derived which collectively support the field production target of 40 Million m3 per day, representing an increase of 14% per day. These measures include the laying of a new pipeline to relieve pressure bottlenecks, adjustment and optimization of the compressors? operational parameters in the processing plant, and choke setting optimization in specific areas. Results clearly demonstrate that the application of optimization technology in the complex infrastructure of the Sulige Gas Field has been successful, and furthermore that it can ensure the gas gathering and transportation system operate in both a stable and efficient manner.

Using practical field data and reference case studies, this paper highlights the positive effects of the optimization process via for example pressure data matching, pressure bottleneck reduction and/or elimination, and compression scenario optimization. The application of optimization technology has provided the end-users with both accurate and reliable results which in turn contribute to improved decision making for the field production and development planning. Moreover it establishes a new management model for the large-scale gas field production system such that any modifications are closely associated to calculated simulation results and are supported by an outlook of maximizing production revenues.
Petrophysical Analysis and Sequence Stratigraphy of the Utica Shale and Marcellus Shale, Appalachian Basin, USA
Authors: Carr Timothy R. , Wang Guochang , McClain Taylor
Published: May 2016

Paleozoic organic-rich mudrock ("shale") units were deposited on the eastern margin of the United States of America from the initial Cambrian rifting to the assembly of Pangaea after the Devonian. Two of these organic-rich shale units the Ordovician Point Pleasant-Utica and Devonian Marcellus Shale of the northern Appalachian basin are some of the most active shale gas/oil plays in the world, and a significant component in the United States energy market. Unconventional hydrocarbon plays are often referred to as statistical plays due to their high degree of heterogeneity, and present challenges for characterization and exploitation. Productivity depends upon an inter-related set of reservoir, completion and production characteristics. A key control on success is regional geology and sequence stratigraphy, in particular the geographic and stratigraphic distribution of organic matter, silica, and carbonate. The distribution of these key elements has been modeled at the basin and local scales. A 3-D mudrock lithofacies model is constructed using sequence stratigraphy to constrain mineral composition, rock properties and organic content. Core analysis and log data were used to calibrate the model from core scale to well scale and finally to regional scale. Geostatistical approaches were used to develop a quantitative relationship between conventional logs and lithofacies, and to model the distribution of mudrock lithofacies in three-dimensions. Controlled primarily by dilution, organic matter productivity, and organic matter accumulation distribution of organic-rich mudrock lithofacies was dominantly affected by water depth and distance to shoreline. The controls on mudrock reservoir quality are subtle and heterogeneity present in Utica and Marcellus results in regional and local well production variations. The proposed 3-D lithofacies modeling approach aids in recognizing geologic and engineering targets, designing horizontal well trajectories, targeting fracture stimulation strategies and understanding shale depositional environments and processes. The proposed approach can be extended to other organic-rich shale reservoirs.
Deepwater Basin Model for the Permian: Delaware Basin Example
Authors: Lew C.L. , Baharuddin S.B. , Pigott J.D.
Published: May 2016

The Permian was an unusual time in the Earth's past, a time of continental accretion, falling sea level, and of global cooling. Basins formed at this time hold some of the most prolific petroleum systems in the world, are well studied, yet still hold much mystery with respect to their relationship between tectonic evolution, sedimentary fill, thermal maturities, and remaining exploration potential. One such important Permian basin is that of the deep Delaware Basin of southeastern New Mexico and west Texas U.S.A. Tectonic subsidence analysis of 11 boreholes reveal best fit kinetic maturities which require one major tectonic extension event from ~268 Ma to ~251 Ma (betas ~1.25 to ~1.53) and shortening from 80Ma to 65Ma (beta ~0.855). Principal source rocks are the underlying Devonian Woodford, Carboniferous Barnett, Permian Wolfcamp, Bone Spring and Delaware Mountain Group (DMG) formations. Modeling shows that the DMG and Bone Spring Formations are presently within the oil window whereas the Woodford and Barnett formations are below the oil window. The DMG began entering early mature oil phase in late Permian. Woodford and Barnett formation began entering the early mature oil phase in the late Pennsylvanian. The Bell Canyon formation is within the main oil window in the deeper part of Delaware Basin (northeast and eastern part of Delaware Basin) whereas the Brushy Canyon formation is within the main oil window in the northern part of the Delaware Basin. Major migration pathways in the Delaware Basin are SE to NW and SW to NE. The critical moment for the accumulation of liquids in the DMG and Bone Spring is Late Permian, around 265Ma -261Ma. Knowledge of the thermal maturity evolution of the Delaware Basin provides important constraints upon determining optimal exploration programs for exploiting liquids and gases either conventionally or unconventionally in these Permian strata.
A New Integrated Hydraulic Fractured Well Spacing Optimisation Technology: A Case Study
Authors: Wang Z. , Liu S. , Cao Y. , Peng Y. , Liu F. , Liu C.
Published: May 2016

The paper presents a new integrated hydraulic fractured well spacing and fracture spacing optimization technology by coupling the techniques of 3D streamline simulation especially the "well influence volume" calculation and horizontal well multistage fracturing optimization with two heterogeneous low permeability reservoirs case studies. The "well influence volume" and Predominant Streamline Fields (PSF) based fractured well spacing is a superior technology for well/fracture spacing design optimization because this technology overcomes the conventional well spacing method, an "acres-per-well" based well spacing technique, which is more suitable for homogeneous reservoir or a homogeneity-anisotropy scheme. For those reservoirs with not only relative low permeability but also having highly heterogeneity vertically and horizontally, the formations change laterally on both rock physical / mechanical properties and on the thickness or even the fluid properties significantly. Without considering those lateral heterogeneities of a reservoir, a fixed shape geometry well spacing technique will fail within a few year of production because of the very early time flooding breakthrough or intensive PSF formed at certain injector-producer well-pair or some spots in the reservoir, which will impact the general EUR of the field as the simulation clearly demonstrated in this paper.

By integrating the 3D fracturing numerical modeling based on local 3D geological models, and reservoir simulation based on a regional 3D model, the "well influence volume" of each fractured well can be better determined through 3D streamline tracking. By maximizing "well influence volume" of each proposed well while keeping the early stage water channeling in check in the future production, we minimize the non-swept reservoir volume, and achieve the best EUR of the reservoir in the most cost-effective way. The fracturing modeling was based wells data such as core analysis and well logging data, and the reservoir simulation was based on the wells data and 3D seismic interpretation and all geological data in the studied reservoir. Numerical results suggest that oil production through the proposed well/fracture placement technology can increase by 22% to 16% comparing with previous work using acreage-well based and uniform elliptical well/fracture spacing method with the same number of wells in placed. The presented technique is a promising fractured well spacing and reservoir development approach for highly heterogeneous reservoirs with low permeability and multi-thin-layer pays because it will reduce the number of wells need or better place them in a cost-effective approach. It is a very beneficial approach for developing those low perm reservoirs like in Bohai Bay region.
Evaluation of Organic Hydrofluoric Acid Mixtures for Sandstone Acidising
Authors: Al-Harbi B.G. , Al-Dahlan M.N. , Al-Khaldi M.H. , Al-Harith A.M. , Abadi A.K.
Published: May 2016

Mud acid, which is a mixture of hydrochloric (HCl) and hydrofluoric (HF) acids, is typically used to stimulate sandstone formations. The success rate of mud acid is limited mainly because of its high spending rate, high corrosion rate, and incompatibility with HCl sensitive minerals; i.e., illite. Organic (acetic, formic and citric) HF acid mixtures, in comparison, have a retarded nature and a low corrosion rate, and are compatible with sensitive sandstone formations; therefore, they can be used as an effective stimulation fluid alternative to regular mud acid.

In this study, dissolution tests of kaolinite, illite or chlorite in acetic, formic and citric with 3 wt% HF acid was conducted. A coreflood was conducted to investigate the ability of organic acids, when combined with HF acid, to remove carbonaceous and siliceous minerals from Berea sandstone plugs at 250 °F. The core effluent samples were analyzed using inductively coupled plasma (ICP). The core plugs were analyzed using the X-ray diffraction (XRD).

All of the tested organic acids were effective in dissolving calcium during the coreflood preflush stage without any indication of precipitation; however, only citric acid extracted aluminum during the preflush, while formic and acetic acids were not effective in leaching aluminum. Additionally, low amounts of aluminum were detected in the effluent of acetic-HF during the main flush and severe damage to the core plug was noticed. Although formic-HF acid extracted a significant amount of calcium and aluminum, there was no change in permeability before or after the treatment. Citric-HF acid dissolved a significant amount of calcium and aluminum, and an apparent increase in permeability was subsequently observed. In addition, a higher permeability ratio was obtained with low HF acid concentrations. This work provides new insights into the applications and potential limitations of organic-HF acids.
Properties of Ilmenite Water-Based Drilling Fluids for HPHT Applications
Authors: Elkatatny S.M. , Nasr-El-Din H.A. , Al-Bagoury M.
Published: May 2016

Barite is the most common weighting material for drilling fluids, which contain several heavy components including lead, cadmium, mercury, and arsenic. Some of these heavy materials can discharge into the sea, which is not allowed especially in the case of oil-based drilling fluid. The supply of barite is geographically limited, with high transportation costs. To overcome the high cost, shortage, and common problems of barite, an alternative weighting material, ilmenite (5 µm), is introduced which is heavier than barite and more stable at high temperature. Also, the micronized ilmenite was introduced to overcome the ECD challenges in some drilling operations at reasonable cost. Extensive lab work was done in order to:optimize the rheological properties of the drilling fluid,determine the optimum pH that gives stable dispersion,assess the thermal stability,optimize the filtration parameters (filtrate volume and filter cake thickness), andcharacterize the ilmenite-based filter cake.

Zeta potential results showed that ilmenite was stable when mixed with water at a pH above 7 and it was dispersed and stable when mixed with the drilling fluid components. Drilling fluids have a density range from 100 to 120 pcf and a plastic viscosity of 28–32 cp. The optimized water-based drilling fluid formula had a small filtrate volume (12 cm3) and thin filter cake (0.2 in.) under dynamic conditions. SEM analysis showed that ilmenite filter cake was heterogeneous and contained ilmenite particles in the layer closer to the rock surface. The kem-seal plus had a big effect to control the rheological properties of the drilling fluid at 350°F. This study will provide a complete evaluation of the drilling fluids with ilmenite as a weighting material and will help drilling engineers to better design drilling fluids for HPHT wells.
Successful Foam EOR Pilot in a Mature Volatile Oil Reservoir Under Miscible Gas Injection
Authors: Ocampo A. , Restrepo A. , Cifuentes H. , Hester J. , Orozco N. , Gil C. , Castro E. , Lopera S. , Gonzalez C.
Published: May 2016

A successful field trial of foams as gas injection conformance enhancer has been deployed in the Cusiana field in Colombia, South America. This work describes the Front End Loading (FEL) process done to get to the field trial, the field operation itself, and the results obtained so far.

The Foam treatment was deployed in the Mirador formation of the Cusiana field, a low porosity quartzarenite with a recovery factor over 50%.The reservoir fluid is a volatile oil developed under an extensive gas reinjection process. The foam treatment was engineered to improve both the gas injection conformance at the wellbore and also the gas sweep efficiency deep into the reservoir.

An extensive FEL including chemical product screening, foam stability at reservoir conditions, coreflood experiments, reservoir modelling, and a careful selection of well candidates was executed for this pilot. The treatment was done in a gas injector well in the northern part of the field, where high RF has already been obtained with high levels of gas recycling.

The operation was performed using the SAG method. The foaming surfactant was pumped selectively in front of the dominant injection layer and then the well was put back on injection. The results showed a clear and sustained change in GI conformance reducing the injectivity of the treated layer by 60%. Increase in oil rate along with decreases in GOR was also observed in the nearby oil producers two months after the treatment. Results herein presented confirm the viability of foams as an EOR method for the Cusiana field and at least two other fields located in the same basin and exploited under similar conditions.

Introduction

The Cusiana field currently operated by Equion Energía Ltd is located in the foothills of the Eastern Mountain chain in Colombia - South America, and started production in 1994. It comprises three stacked reservoirs (Mirador, Barco and Guadalupe) and two compositional fluid systems both being volatile oils with a rich gas cap near critical conditions with pressures and temperatures over 5000 Psia and 250 F respectively (Lee et al, 1996). Initial fluids in place added up to about 1.5 bn STB of oil and over 3 tcf of gas with Mirador formation bearing about 60% of total fluids. Development strategies have included natural depletion, gas recycling, water injection and gas injection redistribution. Gas recycling and re-distribution have provided the best recoveries so far.
Achieving Breakthrough Performance for Multi-Cultural Global Organisations Through Alignment Processes and "One-Culture" Development
Authors: Morris Ronald L.
Published: May 2016

The globalization of business, combined with the necessary localization of staff, is driving a growing diversity in the workforce make-up of multi-national organizations. This, in turn, drives the necessity to improve organizational skills and processes for better communication and buy-in to gain and maintain alignment of these diverse groups. Alignment is a critical factor to organizational efficiency and performance. Attaining a "one-culture" consensus of attitude, rules and business values for the organization is essential, as a starting point, to lay the proper foundation to establish the strategic plan, from vision to business imperatives, goals and objectives.

This growingly diverse workforce mix represents an opportunity and a risk, to either harness cultural diversity as a strength, or to accept it as an inherent weakness to be constantly mitigated. Not to meet this multi-cultural challenge head-on represents a significant risk of organizational functionality, potentially resulting in loss of focus, direction and subsequently performance. However, meeting this challenge in a positive and pro-active way can empower and harness a collective of international and local knowledge, energy and skills that make anything possible.

This paper addresses often ignored or hidden multi-cultural problems and some root causes through three O&G organizations case studies. Also addressed are methodologies used to overcome the multi-cultural challenges and turning a grass-roots strategic planning process into a positive communication and alignment tool. These organizations reinvented and realigned themselves through this systematic process, both internally and with all stakeholders, achieving breakthrough performance.

This paper is intended to be a help to companies and leaders embarking on a new country entry organization or re-energizing flagging multi-cultural organizations. While not a definitive or comprehensive investigation of the subject, one of the main objectives of the paper is to bring these challenges to light and open the subject for further attention and development.
Iterative Dip-Steering Median Filter: A New Approach to Separation of Simultaneous Sources
Authors: Huo Shoudong , Zhu Weihong , Luo Yi , Kelamis Panos G.
Published: May 2016

Simultaneous source acquisition technology, also referred to as 'blended acquisition', involves recording two or more shots simultaneously. Despite the fact that conventional processing procedures can still produce acceptable images from the blended data, it is still desirable to separate the blended data into single shot gathers, which allows to reduce the crosstalk noise and to allow application of standard pre-stack processing, such as statics, velocity analysis, etc.

In this paper we introduce a new and simple Iterative Dip-Steering Median Filter (IDS_MF) in order to separate the blended seismic shot gathers. This method extends the well-known conventional median filter which works well with horizontally-aligned coherent events but cannot handle steep events, especially events with conflicting dips. It first identifies the dominant dips inside a processing window by a Fourier-Radial transform in the frequency-wavenumber domain. A median filtering is then applied along the dominant dip in order to separate the signal. The data are processed along the remaining dominant dips in an iterative manner until all signals have been retained.

The IDS_MF method can be used for random or spike noise attenuation. It does not require that reflections or events are hyperbolic and can be applied on any gather such as Common-shot, CMP, Common-receiver and Common-offset. IDS_MF does not require special acquisition geometries and works well for both 2D and 3D data as well as land and marine seismic surveys. The main limitation of the method is that it relies on local coherency. It produces very good deblending results when the residual statics are properly accounted for. Field data is used to demonstrate the performance of the proposed de-blending technology.

Introduction

Simultaneous source acquisition technology, which records many sources from different locations almost simultaneously, can significantly increase field acquisition efficiency at the expense of crosstalk noise. Processing techniques must be developed to minimize the crosstalk contanmination inherent to this type of recording.

The idea of shooting several sources almost simultaneously to acquire faster has been extensively documented by Bagaini (2006). The land attempts commonly employ specially encoded source sweeps, which make it possible to decode the interfering source responses. In marine seismic acquisition, Beasley et al. (1998) proposed to place the air guns symmetrically off the ends of 2D marine cables and firing the sources simultaneously. Vaage (2002), Hampson et al. (2008) and Dragoset et al. (2009) introduced a small random time delay (dithering) into the second source. Because of this delay, the interference between sources appears random in some sort domains, such as the common-receiver, common-offset and CMP domain.
Continental Carbonates Reservoirs: The Importance of Analogues to Understand Presalt Discoveries
Authors: Virgone Aurelien , Broucke Olivier , Held Anne-Edwige , Lopez Benjamin , Seard Claire , Camoin Gilbert , Swennen Rudy , Foubert Anneleen , Rouchy Jean-Marie , Pabian-Goyheneche Cecile , Guo Li
Published: May 2016

Recent discoveries offshore Brazil have induced a renewal of interest in the study of recent and ancient continental carbonate systems which developed in a wide range of depositional settings, reflecting aerial to subaqueous environments.

Recent and ancient continental carbonate analogs provide some keys to depict the sedimentologic/sequential pattern observed at the core scale and help in the understanding of the impact of climate change, fluid flow and water chemistry on the carbonate factory. It is noteworthy that the widespread microbial development in continental carbonate systems occurs in stratigraphic intervals typified by specific climatic and geodynamic conditions, and sometimes coincides with similar development in the marine realm. Stromatolites are more developped in high water level condition. But comparative studies between intracratonic (Recent Great Salt Lake; Eocene Green River lacustrine systems) and rift lacustrine systems demonstrates that they are more extensive on a flat substrate. The control exerted by the topography may increase during abrupt alternations of arid and humid periods, influencing the water chemistry and, accordingly, leading to the development of anoxic and/or evaporitic conditions. The key issue is therefore to understand the development of carbonate in lacustrine condition, how the sedimentary bodies and features can be preserved, and how their good reservoir properties can be maintained. High subsidence rate will influence the preservation potential of the relevant carbonate bodies, while the geothermal gradient, water chemistry or volcanic activity will impact the reservoir properties.

In addition, meteoric or thermogenic travertine deposits, are an additional carbonate product that must be considered in the evaluation of continental carbonate reservoir systems.
Utilisation of Lasers in Petroleum Drilling Industry
Authors: Bazargan M. , Madani A. , Sharifi H. , Jalalyfar H. , Ghassemal askary K. , Rostamian A.
Published: May 2016

Due to constructive role of technology developments in petroleum industry and their affects in reducing the costs of drilling, it is necessary to use future technologies. One of these new progresses taking very effective role in drilling industry is to get use of laser in drilling processes. The aim of this paper is to categorize and represent the different study results and also to analysis the principle and advantages of laser drilling. Compared to prevalent drilling, laser drilling is capable to augment the efficiency of drilling and solve its problems such as increasing the rate of penetration, monitoring the bottom hole, diminishing equipment and drilling process, but faces some problems such as laser beam transference, cleaning the down hole. As a result, the benefits of laser drilling overcome the problems and it can be replaced or combined in bits in early future. in this paper we showed the result of using laser technology during drilling operation. Also, In this paper we experiments on changing wavelength transmitted during fracturing and drilling.
Petrophysical Seismic Inversion Over an Offshore Carbonate Field
Authors: Souvannavong Vimol , Allo Fabien , Coleou Thierry , Colnard Olivier , Machecler Ingrind , Dillon Lucia , Schwedersky Neto Guenther , Nunes Cassiane , De Abreu Elita , Colpaert Arnout , van Wijngaarden Aart-Jan
Published: May 2016

The main objective of this project was to evaluate the ability to derive petrophysical properties like porosity from pre-stack seismic data in a carbonate environment. We apply a direct petrophysical inversion technique to an offshore carbonate reservoir. Starting from an initial geological model in depth and a number of carefully conditioned seismic angle stacks, we derive a detailed 3-D model of the porosity and hydrocarbon saturation matching the observed seismic data. We use a well-calibrated Petro-Elastic Model (PEM) to link the petrophysical properties to the seismic velocities. We compare inversion results obtained using the Xu-Payne and T-matrix PEMs which both account for carbonate pore geometry, lithology, porosity and fluid content but have different elastic sensitivity to fluid saturations. The inverted results provide detailed images of the spatial variations of porosity and fluid content across the reservoir interval. Obtaining estimates of absolute saturations values is more difficult, as saturation estimation is strongly dependent on the choice of PEM.

Introduction

Carbonate reservoirs are notoriously heterogeneous. Seismic inversion is therefore needed to help estimate the spatial variations of rock type, porosity and fluid content in between the available wells. We present the results of a direct inversion of porosity and saturations from seismic pre-stack data over an offshore carbonate reservoir.
Intensive Use of 4D Seismic in Reservoir Monitoring, Modelling and Management: The Dalia Case Study
Authors: Pluchery E. , Toinet S. , Cruz P. , Camoin A. , Franco J.
Published: May 2016

Introduction

Born nearly thirty years ago, time lapse (4D) seismic monitoring technology has been developed in some cases to monitor fluid movement and to distinguish between drained and un-drained portions of a reservoir. It allows quantitatively improving reservoir models, particularly their predictive capability. Indeed, the benefits of time-lapse seismic for reservoir characterization depend on the quality of 4D acquisition and processing, but they also greatly depend on the particular 4D inversion and interpretation methods used. Finally, a decisive aspect is certainly the capability of integrating results from different disciplines in an effective way. Timing is also crucial: results delivered in a few months can have a direct operational impact such as field monitoring or well location and design optimization.

For the last ten years, Total has recognized the importance of time lapse seismic and has therefore conducted 4D seismic monitoring in different geological environments. Examples of 4D experiences range from monitoring of water injection and production for complex reservoir management and field development in the Gulf of Guinea (Angola and Nigeria); monitoring of geomechanical effects in HPHT fields (Elgin-Franklin, UK), in compacting reservoirs in Norway (Ekofisk and Valhall) and in the Gulf of Mexico (Matterhorn, US); monitoring of steam chamber in tar sands (Surmont, Canada) and monitoring of compaction and water rise in carbonates (South-East Asia). This paper focuses on the intense use of 4D seismic on the DALIA Field (Angola, Block 17).
A New Method to Interpret Hydraulic Fracture Complexity in Unconventional Reservoir by Tilt Magnitude
Authors: Wang Xin , Ding Yun Hong , Xiu Nai Ling , Wang Zhen Duo , Yan Yu Zhong
Published: May 2016

Hydraulic fractures in unconventional reservoir are complex. Surface tilemeter fracture mapping method is used to obtain ground deformation field caused by hydraulic fracture. The observed and theoretical fracture-induced tilt vectors from a best-fit fracture solution are compared and obtain hydraulic fracture orientation and shape. Through analysis of the vertical and horizontal component volume, three new parameters are given to characterize the fracture complexity, i.e. ratio of fluid volume to fracture volume R; volume weight difference rate D and fracture complexity index ß. These new parameters are used to explain the mapping result of shale and coal seam reservoir. The results show that R of coal bed and shale is 2.2 and 2.9 while sandstone is only 1.4. ß of shale, coal bed and sandstone are 0.7,0.4 and 0.3 respectively, the two new parameters show hydraulic fractures in unconventional reservoir are very complex. The new parameters can describe fracture complexity very well, and results are correlated well with the results of fracturing pressure analysis and other methods of monitoring. This method provides valuable information for optimizing fracturing treatment design and postfrac evaluation in unconventional reservoir.
Experimental Investigation of Hydraulic Fracture Propagation in Acoustic Monitoring Inside a Large-Scale Polyaxial Test
Authors: Liu Yuzhang , Cui Mingyue , Ding Yunhong , Peng Yi , Fu Haifeng , Lu Yongjun , Liu Yunzhi
Published: May 2016

Field experiences suggest significant interaction between natural fractures and hydraulic fractures in unconventional reservoir and some tight gas sandstone. Microseismic monitoring is a widely used methodology to understand the real-time evolution of fracture geometry during hydraulic fracturing, which is essential for evaluating the SRV under certain treatment, especially in unconventional reservoir. Howerver, the correlation between the real fracture geometry and microseismic monitoring results is still open to discuss. Therefore, understanding the relationships between the induced fractures and acoustic emission in different laboratory conditions is of high importance for studying the mechanism of hydraulic fracturing and ultimately optimizing fracture complexity.

A large polyaxial testing system was built for investigating the factors of inducing complex fractures in sandstones, shale and coal for hydraulic fracturing treatment. This paper presents the experimental results of a study conducted to understand the mechanism of fracture initiation and propagation based on acoustic emission monitoring. Large-scale test was conducted in dry sandstone outcrop of 762×762×914mm to simulate the hydraulic fracturing. True triaxial stresses were applied to the specimen. The acoustic emission events associated with fracture propagation or failure process during injection were monitored to provide further data to characterize the fracture. The hydraulic fractures and oil penetration surface were observed after injection.

Results show that the acoustic emission monitoring is in good accordance with the split block surface dyed red. AE localizations clearly demonstrate fracture initiation and propagation dynamics in the sample which can be used to control the fracture. The AE rates increased with opening hydraulically induced fracture and its closure. The real-time fracture geometry can be calculated by integrating the borehole pressure, AE localizations, injection rate, fluid leakage and rock mechanical properties. We are currently investigating various ways for building the fracture propagation model. The work presented here a new hydraulic fracturing testing system integrated with geophysical monitoring and processing technologies that will improve laboratory study of hydraulic fracturing mechanism and provide a trial on new ideas and technology