bluuebunny/crossref_metadata_2025_split huggingface dataset:
Sequence Stratigraphic Study of Areas 3 and 6, Rovuma Basin, Mozambique
Authors: Sapri Dayang Hasspariah , Mahmud Othman Ali , Wei Chen Harry Wong 
Published: May 2016

Abstract
The paper presents the results of intergrated sequence stratigraphic study carried out for the Areas 3 & 6 in Rovuma basin, offshore Mozambique. Five depositional sequences have been recognized that cover from Triassicto recent. A conceptualized petroleum system model is presented and the upside potential traps in this area are also highlighted and discussed.

Introduction
Areas 3 & 6 are located in the southern part of Rovuma basin that partly located in coastal and deepwater area in the North Republic of Mozambique (Figure 1), approximately 1,600 km northeast of Maputo, the capital of Republic of Mozambique (ENH, 1994). PETRONAS Carigali Mozambique (Rovuma Basin) Ltd (PCMRB) is the Operator for Areas 3 & 6 and Empresa Nacional de Hidrocarbonetos (ENH) is the partner.
The Rovuma basin has been proven to be hydrocarbon bearing from previous discoveries made in the area. Three significant commercial gas discoveries have been reported in the Rovuma basin; Mnazi Bay-1 (1982), Windjammer-1(2010) and Barquentine-1 (2010) (IHS Energy, 2010). All discoveries are made in the Rovuma delta area about 150 to 200 kms to the north of study area. Area 3 & 6 are considered as an underexplored acreage as of to date there are no wells drilled in the area, the nearest well is Mocimboa-1 which is located about 150km to the north.
To evaluate the hydrocarbon potential of Rovuma basin, specifically in Areas 3 & 6, a regional study using sequence stratigraphic approach was carried out by (PCMRB) in 2010. The main objective of this study is to establish a sequence stratigraphic framework for Areas 3 & 6, and to provide the regional geological understanding in term of tectonic settings, basin evolutions and total petroleum systems. In addition, the study is also designed to identify any available play types and to develop new play concepts in the area. The results of the study will be used as a foundation to facilitate future detailed exploration activity in the blocks.
Integrating Horizontal Wells in 3D Geological Model Using Sequence Stratigraphic Framework in Braided Channel Complex of the Changbei Gas Field, Ordos Basin, China
Authors: Muda Pranata Haruji , Wu Lei , Navpreet Singh , Su Wu , Xu Li , Yang Yatao , Wu Pincheng , Yang Ping 
Published: May 2016

Abstract
Multi-lateral horizontal wells are applied in Changbei Field to maximize economic development of tight gas sandstone reservoir. Reservoir models utilized for well planning were largely controlled by vertical wells. However, after drilling many horizontal wells, the reservoir model is required updating with horizontal wells to improve well placement and planning of the remaining horizontal wells. One of the prime challenges was effective and correct incorporation of horizontal well data into the reservoir model, this was particularly challenging in Changbei's braided channel complex with high reservoir heterogeneity.
Horizontal well objectives in Changbei Field are to drill 2km dual lateral wells into clean Quartz Arenite Sandstones that were deposited in high to moderate energy facies and avoid low energy and abandonment facies which are typified by dirty sandstone (lithic quartze arenites), carbonaceous claystone and shale. This objective has biased well data to the better reservoir quality in horizontal wells compared to vertical wells and subsequently results in significant deviation of facies distribution and reservoir properties.
By integrating all data available including core, thin sections, wireline log, mudlog, outcrops and analogues data, this paper takes braided channel of Changbei tight gas field as an example on methodology of incorporating horizontal well data based on high-resolution stratigraphic correlation.
The result has a significant impact on Changbei Field Development Planning. The clarity in main sand reservoir distributions (QA Sand) has improved horizontal wells placement and planning to be more efficient and cost effective. This improvement has been proved by better history matched with production data and better predictability while drilling horizontal wells.
Variable Depth Streamer: Benefits for Rock Property Inversion
Authors: Michel L. , Lafet Y. , Coffin J. 
Published: May 2016

Abstract
The lack of low frequencies in conventional seismic data means that a low frequency model must be incorporated in seismic inversion process in order to recover absolute elastic attribute values. Typically, low frequency models are obtained from low-pass filtered impedance logs. If well-logs are sparse and the geology complex, the derived low frequency model may be inaccurate and cause biased inversion results. One option to improve the low frequency model is to use seismic velocities. Seismic velocities provide information at very low frequencies, they are not providing information for all missing frequencies. Seismic data acquired using variable depth streamers (VDS) are suited for inversion as they provide directly the missing low frequencies, hence removing the need to build low frequency models from well data. In order to quantify the impact of the low frequency content on seismic inversion, comparative elastic inversion tests were conducted using 2-D seismic data from Constant Depth Streamer (CDS) and VDS acquisitions. Both datasets from offshore NW Australia were acquired simultaneously. Both data sets were processed using PSTM sequences and inverted. Two gas-bearing sand reservoirs are identified. Delineation of reservoirs is improved with VDS seismic inversion which shows lower impedance and Poisson ratio values in the gas-bearing interval. The inversion results were subsequently interpreted in terms of facies using a supervised Bayesian classification procedure. Three litho-classes were considered: gas-sand, water-sand and shale.

Introduction
Quantitative interpretation teams need to solve two problems when using model-based inversion: extracting meaningful wavelets and building accurate low frequency models. Conventional seismic data are band limited and a low frequency model must be incorporated in the inversion process in order to recover absolute impedance values. Typically, low frequency models are obtained from low-pass filtered impedance logs. If well-logs are sparse and the geology complex, the well-derived low frequency model will be inaccurate and cause biased inversion results. One commonly used method to improve the low frequency model is to use seismic velocities. However, while seismic velocities provide information at very low frequencies [0–4 Hz], they are not usually providing information for the missing frequencies in the range from 4 to 10 Hz. Seismic data acquired using variable depth streamers are ideally suited for inversion as they provide directly the missing low frequencies, hence removing the need to build low frequency models from well data. In order to quantify the impact of the low frequency content on seismic inversion, comparative elastic inversion tests have been conducted using 2-D seismic data from Constant Depth Streamer (CDS) and Variable Depth Streamer (VDS) acquisitions.
Transgressive-Regressive Cycles in the Malay Basin: New Insights
Authors: Jirin Shamsudin , Mohamed Mahani , Hasan Sanatul Salwa 
Published: May 2016

Abstract
The Malay Basin is a prolific hydrocarbon producing basin located off the east coast of the Malay Peninsula (Fig. 1). It started as an extensional / rift basin during the Oligocene, followed by thermal subsidence in the Early Miocene. Compression started sometime in the Middle Miocene which resulted in localized inversion. Maximum basin inversion was recorded during the late Middle Miocene The stratigraphic scheme generally used for the Malay Basin is shown in Fig. 2. Understanding transgressive-regressive cycles, and their controlling factors, have important influence on Malay Basin sedimentation, and hence directly impacts exploration efforts in the basin. Seismic data and biostratigraphic analysis carried out since the 1980's showed evidence of periodic marine transgression as early as Late Oligocene (Group L). Although several marine transgression events were recorded (Fig. 3), the biostratigraphic data indicates that during much of Miocene the basin did not become fully marine until the Pliocene. The limited occurrence of a fully marine faunal assemblage indicates a restricted marine condition. In many instances the presence of common to abundant freshwater algae further indicates intermittent development of 'lacustrine' conditions within the Miocene (Fig. 4).
In the Malay Basin the transgressive-regressive cycles are believed to be the result of interplay of tectonic and sea level fluctuations (Mazlan, 2011), particularly during the Miocene. Evidence of tectonic deformation includes the presence of basement highs in the southern end of the basin (Fig. 5), and these would have exerted a significant impact on the depositional environment, and consequently the sedimentation patterns. This basement high is thought to behave as a sill which prevents the Malay Basin from being fully connected to the sea. The long term uplift of the basement high in the south would have been superimposed with fluctuation of sea level (Mazlan, 2011; Fig. 6). There would be instances where sea level rises exceeded the rate of tectonic uplift. During such time the sill or 'gate' would have opened up and caused marine flooding into the basin. At other times, the basin would be disconnected from the sea and lacustrine conditions would be established.
Downhole Electrical Heating for Heavy Oil Enhanced Recovery: A Successful Application in Offshore Congo
Authors: Bottazzi F. , Repetto C. , Tita E. , Maugeri G. 
Published: May 2016

Abstract
The development of heavy oil reservoirs is one the future targets of the major oil companies worldwide. Most of the heavy oil fields are produced through cold production methods leaving behind significant amounts of unproduced reserves. Today several EOR (Enhanced Oil Recovery) techniques and, in particular, thermal methods are available to achieve higher recovery factors.
However, some technologies, like the downhole electrical heating have been recently improved, allowing enhancement of production, therefore, improvement of the recovery factor with relatively low investment cost with respect to the high costs involved in the implementation of the thermal technologies.
In order to increase the production of a heavy oil reservoir in the offshore Congo, a study of down hole electrical heating application have been carried out showing encouraging results.
The aim of the study was to evaluate the benefit associated to the application of this technology through the reservoir modeling. Significant results were achieved in terms of increasing of the recovery factor.
The use of heat to increase the reservoir temperature showed good results in terms of heavy oil viscosity reduction starting from 1,000 cP at reservoir conditions (34°C) down to much lower values throughout the production time resulting in increased production rate and consequently, higher recovery factor from this reservoir.
The first application of this technology has been performed in a long horizontal well section of about 500 meters length completed with production sand screen. The electrical heating mineral insulated three phase cables were deployed throughout the horizontal well section by means of a dedicated completion tail pipe.
Several design challenges have been faced to properly centralize the heating cables and clamp the same around the completion tail pipe due to the well design constraints.
This paper will describe the results of the reservoir modelling analysis, the completion planning activities and the lessons learned during the operations.
Next Generation Borehole Seismic: Dual-Wavefield Vibrator System
Authors: Nalonnil A. , Marion B. , Minto J. 
Published: May 2016

Abstract
Recent advances in crosswell seismic technologies have lead to the successful development and release of a new downhole seismic source that imparts greater energy into the formation by sweeping frequencies in the range of 30–800 Hz. The result is, for the first time, a powerful, efficient and cost effective vibrator for use in the borehole allowing for enhanced seismic imaging between wells up to 2km apart.
In addition, the patented design and operation of the source allows for both compressional and shear wave energy to be acquired simultaneously along with the flexibility of being able to acquire data in reverse vertical seismic profile configuration.

Introduction
Crosswell imaging is a technique that has been in practice for the past 15 to 20 years and much has been published about the traditional downhole sources that have been used which include electrical sparkers, weight drops and piezo ceramic vibrators (Figure 1). With these high frequency transmitters, several inherent factors have impeded the application in well separations greater than 1 km and hence wider acceptance in the seismic imaging options available for field development. These factors are attenuation of the higher frequencies, different frequency bandwidth from surface seismic and lack of direct shear wavefield content.
This paper discusses key features of a newly developed downhole seismic source (Z-TracTM) that helps address the challenges stated above. This magnetically clamped source is intended specifically for formations with high attenuation and large distances between wells. Operating at a lower frequency range (30 Hz-800 Hz), this source produces about 20 dB more amplitude than current piezoelectric sources. It also produces direct compressional and shear energy waves, allowing for advanced wavefield analysis. It distributes the energy produced over an area in the wellbore that is large enough not to cause damage to the casing or cement.
Results from recent case studies are also presented to highlight the benefits being seen in various applications from around the world. Brief descriptions of the acquisition and processing methodologies are also referenced as a background to the case results shown.
A Simulation-Free Approach for Well Placement in Tight Gas Reservoirs
Authors: Zhou Yijie , King Michael J. , Du Song 
Published: May 2016

Abstract
Well placement in an infill drilling program is a routine procedure for reservoir management. In tight gas reservoirs specifically, well locations depend upon the internal reservoir heterogeneity, the complex dynamic reservoir response associated with depletion history, and also the uncertainties associated with the reservoir parameters. This paper introduces a rapid simulation-free procedure to determine infill well locations, which also takes reservoir uncertainty into consideration.
The general practice of well placement usually requires reservoir simulation to predict the dynamic reservoir response. Numerous well placement scenarios require many reservoir simulation runs, which may have significant CPU demands, and this is only for one specific realization. Furthermore, to account for the geologic uncertainty, people tend to consider multiple realizations, thus make it more expensive, even impractical, for large scale simulation for each realization.
This paper proposes a novel simulation-free screening approach based on a combination of static and dynamic reservoir properties. The areas with higher values (ranks) are poorly drained, and thus become the sweet spots for drilling the infill wells. The dynamic property discussed in this paper is pressure, since primary depletion is the recovery mechanism for tight gas reservoirs. We introduce and utilize a geometric pressure approximation, which is a simulation-free approach, to access the pressure changes during depletion history. The geometric pressure approximation may not give the exact pressure solution, but the pressure ranking from the approximation is quite close to the flow simulation, thus good enough for the model screening.
The screening process produces a quality map, based on a deterministic model. This paper also generates the corresponding risk map to capture the geologic uncertainty. We have the most confidence about the reservoir data at the existing well locations. As the distance from the existing wells increases, our confidence about the data at this new location decreases, and the risk correspondingly increases. This risk map is generated through a spatial connectivity analysis. Combining the quality map and risk map, good infill well locations and a drilling sequence can be determined for improved reservoir management.
We demonstrate this approach based on a U.S. on-shore tight gas reservoir. We study a section of this tight gas reservoir first to verify this approach by the comparison with flow simulation results, and then apply this method to the the large scale model to determine the infill well locations at each stage and propose an appropriate drilling sequence for the decision maker. Current work only examines vertical wells. We expect to further extend this workflow to study more complex well trajectories and fracture design in the future.
Next Generation Onshore and Offshore Seismic Acquisition Technologies
Authors: Hwang Jay , Walk Wim , Baeten Guido 
Published: May 2016

Summary
We present the business and technical underpinning for developing revolutionary onshore and offshore seismic acquisition technologies in order to meet the challenges of the new E&P business portfolio. In this paper we will also describe new seismic acquisition systems developed with external technology partners and report their progress. These new systems aim at disrupting both the onshore and offshore seismic industry by delivering accurate and high quality seismic data with significant cost improvement. For land Shell is pushing toward a million channel system development in order to drastically drive the cost down with high receiver and source efficiency, and strongly improve the seismic quality with WAZ, long offsets, and the broad band. For the offshore, a multi-source fast deployed ocean bottom node (OBN) system is being developed to drastically reduce the survey cost such that it can be cost effectively applied to large exploration surveys as well as higher resolution surveys for 4D. Shell expects to commercialize these new technologies with partners in order to deploy them to Shell assets in the nearer term and industry in the longer term.
Petrophysical Evaluation of Shale Oil & Gas Opportunities in Emerging Plays; Some Examples and Learning's from the Americas
Authors: Tepper Brian , Baechle Gregor , Keller Jim , Walsh Robert , Quint Edwin 
Published: May 2016

Abstract
Determination of porosity, hydrocarbon saturation and net reservoir thickness in unconventional shale oil and gas reservoirs is often a major petrophysical challenge due to the low porosities typically present in these reservoirs and the impact of kerogen on fundamental rock properties such as the grain density, porosity and permeability. The challenge is large in emerging play areas where core measurements are limited or not available, and quality information on total organic carbon (TOC) content and mineralogy may be sparse. Legacy wireline logging measurements such as Resistivity, Gamma Ray, Density, and Sonic are often the primary source of rock property information. Deriving accurate ranges for key volumetric parameters is essential for risking and assessing an economic value for these plays. Also important for assessing economic value is predicting the effectiveness of fracture stimulation to achieve expected ultimate recoveries (EUR's) that are economically attractive. This requires interpretations of the mechanical properties of the reservoir. The petrophysical characterization for emerging plays can be enhanced by utilization of analog core based trends as well as learnings gained from developing and mature plays. This paper focuses on the use of analogs to improve the petrophysical characterization in emerging plays where uncertainties are generally large.

Introduction
The petrophysical evaluation of shale oil and gas reservoirs in emerging play areas is often very challenging. As in most shale oil and gas reservoirs, a basic understanding of the matrix lithological components, clay content, kerogen content, and maturity level is required for deriving reasonable ranges in key volumetric parameters such as the porosity, hydrocarbon saturation and net reservoir thickness. In emerging play areas, legacy wireline logging measurements such as Resistivity, Gamma Ray, Density, and Sonic are often the primary source of rock property information. Core measurements are limited or not available, and quality information on TOC and mineralogy may be sparse. As such, the volumetric parameters can have very large uncertainties. To reduce or manage these uncertainties, it is important to leverage data and learnings from developing and mature plays where there may be an extensive knowledge base of log and core data. This paper outlines a workflow for developing and using analog trends to improve the petrophysical evaluation in these challenging emerging plays.
Real-Time Downhole Coiled Tubing Communication System Allows Optimised Well Intervention and Reservoir Evaluation - A Two Well Case Study from New Zealand
Authors: Li Yang , Sturgeon Trevor 
Published: May 2016

Abstract
New Zealand is known for deep, highly deviated wellbores often causing difficult wellbore interventions. This paper will highlight several coiled tubing (CT) interventions successfully completed in New Zealand with the help of a CT conveyed real-time downhole communication system.
Well A in the study is a highly deviated gas producer which was to be converted into a gas re-injection well. A CT acid wash was required to remove deposited scale from the wellbore followed by a production log. The particular challenge with entering this well, in addition to the total depth of 7,395m, was that previous attempts hung up in a damaged seal assembly at 6400m and 66 degrees hole angle. It was decided that real-time data transmission / logging could help to increase the chances of successful CT intervention.
Well B was a newly completed monobore well that was programmed for hydraulic fracturing completion in three zones. Underbalanced perforation and pre-frac flow testing was accomplished using a CT system on each of the three zones to evaluate the well productivity. To provide an accurate depth correlation for the perforating operation and to optimize the reservoir evaluation process, a real-time CT conveyed down-hole communication system was selected and successfully run.
In both case histories, real-time data from downhole tools was obtained by utilizing a small diameter conductor wire which is pre-installed inside the coiled tubing. With mechanical and electrical quick connectors attached on the bottomhole assembly (BHA), a data acquisition system on surface can obtain real-time information from the casing collar locator (CCL), the down-hole pressure and temperature gauges, proving very valuable information for both CT and reservoir engineers to optimize their operations. Additionally, the CT string, with pre-installed conductor wire, allowed logging tools to be attached, retrieving live data from down-hole and allowing an optimized logging program to be performed on the fly.
This paper reviews the coiled tubing real-time down-hole communication system and discusses the benefits of running it over conventional coiled tubing by illustrating case studies of successfully running the system from above two wells.