bluuebunny/crossref_metadata_2025 huggingface dataset:
Application of Curvature Attributes in Prediction of a Carbonate Reservoir
Authors: Yuan Shihong , Wan Zhonghong , Bai Xuelian , Chen Maoshan , Han Ruidong
Published: May 2016

Seismic curvature attributes, as being second-order derivatives of seismic information, allow interpreters easily to map the structural deformation and subtle stratigraphic details that are not readily observable through seismic data or first-order derivatives such as the dip magnitude and the dip-azimuth attributes. The conventional computation of curvature measures may be termed as structural curvature, generated from lateral second-order derivatives of time-structure component of seismic data, and provides the information related to time structure. Likewise, amplitude curvature, as being lateral second-order derivatives of amplitude component of seismic data, contains the information about lateral change of seismic amplitude. In this paper, we apply the most-positive and most-negative amplitude curvature measures to characterize a carbonate reservoir in Tarim Basin, NW China through computing the first order derivatives of the inline and crossline components of the energy-weighted amplitude gradients. The most-positive amplitude curvature measure is very effective to represent the internal features of the channels and fractural-vuggy systems, while the most-negative amplitude curvature highlights the lineament details near the edges of the channels and fractural-vuggy systems. In addition, application of multispectral amplitude curvature computation to prediction of the carbonate reservoir shows that the long-wavelength amplitude curvature attributes depict the larger scale geological features as compared with the short-wavelength amplitude curvature measures which focus on the local details. In brief, integrated application of long- and short-wavelength computation of most-positive and most-negative amplitude curvature attributes exhibits the characteristics of the carbonate reservoir from different sides.
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

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

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

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

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

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

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

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

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

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

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.
Application of Probabilistic Neural Network on Complex Carbonate Reservoir Prediction
Authors: Sun Xuekai , Sun Sam Zandong , Jiang Shan , Luo Chunshu , Yang Haijun , Pan Wenqing
Published: May 2016

Carbonate reservoir in Tarim basin is more complex for its strong heterogeneity and anisotropy. Different from the usual, this paper mainly focused on how to employ PNN as a comprehensive method in detecting the dissolved caves for carbonate reservoir, in which advantages of inversion and attributes are both used. During the entire workflow of PNN, we emphasize the importance of seismic attributes searching and cross validation. And the P-velocity and S-velocity of a test area selected from ZG8 area are predicted by utilizing PNN technique, and the interpretation of Formation Yingshan is conducted on the established indicator of Vp/Vs. Results show that the resolution is greatly boosted and the dissolved caves are distinctively and vividly characterized, which is seldom achieved by pre-stack inversion.

1 Introduction

The great potential of carbonate reservoirs in Tarim basin is widely accepted. However, situations are rather complex than conventional reservoirs. In the past geological history, carbonate rocks in this area experienced multi-staged tectonic movements and dissolutions. Consequently, the main storage space for oil and gas at present are mainly the dissolved caves and fractures instead of the primary pores. Strong heterogeneity and anisotropy brings great difficulties and challenges for discovering and characterizing complex carbonate reservoirs (Sun et al., 2012). For this reason, it is obvious that only a single technique is insufficient to deal with the challenges we meet in complex carbonate reservoir prediction.

And the theoretical basis of probabilistic neural network (PNN) is founded and improved by Specht and Donald in early 1990s. Actually, PNN is more like a mathematical interpolation scheme which happens to use the neural network architecture for its implementation. Compared with multi-layer forward network, PNN behaves much better for its remarkable robustness and efficiency. PNN was first used in the image and signal processing (Masters, 1995), and it was Hampson that introduced this technique into geophysical world through a case study, in which the the porosity of a sand reservoir was successfully estimated by incorporating several attributes (Hampson et al., 2001).Although many studies and practices proved that PNN can serve as a powerful tool by incorporating various results from different explanation techniques in the past decade(Xie et al., 2004; Wang et al., 2004; Wu et al., 2011), however, carbonate reservoir is seldom involved in these studies.
Potential Application of Downhole Gas Compressor to Improve Productivity for Gas Reservoir
Authors: Hossain Md Mofazzal , bin Mohd Ismail Mohd Dali
Published: May 2016

Downhole Gas Compression (DGC) is the new form of Artificial Lift Technology used to increase the productivity of gas wells. Surface compressors are commonly used to reduce the pressure at the wellhead, which in turn reduces flowing bottom hole pressure, and boost the well productivity for a gas well especially during its decline phase when average reservoir pressure falls to a value equal to the pressure in the wellbore imposed by the sales line at the surface, plus the pressure losses that occur in the gathering system and the tubing. This conventional technique is not very efficient for the gas wells that produce significant amount of liquid (water or condensate), since this liquid needs to be separated before reaching the gas compressor. In addition, it also requires additional space for compressor assembly into the well, which may be very challenging for wells in offshore and subsea environment. As an alternative to surface compressors, down hole gas compressors technique can be applied to increase the well productivity, especially gas wells in offshore and subsea environment. Some study claimed that this new technology could: increase more than 30% of gas production; resolve many multiphase related issues; and delay the onset of liquid loading. However, numerous challenges associated with design, development and implementation of this new technology are not well understood or documented. This study has been focused to understand the key concepts of the technology and explore its potential application for increasing well productivity of gas wells through sensitivity studies. This paper presents principles mechanisms including theoretical background of DGC techniques, and results of sample case studies based on sensitivity analysis with aims to identify key factors to be considered for successful deployments of DGC into a gas well for natural gas reservoir. The paper also summarizes key findings which may be used as potential guidelines while considering for possible implementation of DGC technique during field development planning.
Determination of Effective Flow Properties of Caprocks in Presence of Multi-Scale Heterogeneous Flow Elements
Authors: Ma Jingsheng , Couples Gary , Drews Michael , Kurtev Kuncho , Aplin Andy
Published: May 2016

Determining the effective fluid retention capacity of caprocks is of importance to petroleum exploration and production, and to CO2 storage in the subsurface. Thick successions of mud-rich sediments can comprise a range of genetic units (GUs), including mud-dominated hemipelagites, channel-levees, and mass-transport deposits. These GUs are characteristic of slope settings within the deep-sea environment. Based on measured properties of small samples, mud-rich sediments within these GUs ought to be high-quality caprocks with very low permeability and high capillary entry pressure (Yang & Aplin, 2007). However, each GU also contains objects of much more permeable materials such as fine sands and silty sediments. Those bodies are in the form of sub-seismic, typically centimeter thick, thin layers, which may or may not be deformed during the process of basin evolution, but they can have considerable lateral continuity. Moreover, GUs may contain deformation-related flow conduits, such as sandy injectites and open fractures, which function as pathways for vertical fluid migration. These GUs may themselves be arranged in complex patterns due to depositional and deformational processes. Such multi-scale heterogeneity in caprocks can affect their fluid retention capacity.

Estimating the effective fluid retention capacity of caprocks involves the quantification of properties at a sample (10-2m) scale in the laboratory. Sample compressibility, permeability and threshold Capillary Entry Pressure (CEPt) could be constrained well by lithology (e.g. sand/silt/clay ratio) of sediments, and at normal conditions they could encapsulate finer-scale heterogeneity satisfactorily too. However, the direct use of those properties on blocks of 1000mx1000mx100m size in basin simulations is highly undesirable and risky if each block corresponds to full or part of one or more heterogeneous GUs. Therefore, the lab-based properties must be upscaled to the block scales through multi-stage upscaling. To do this, we need: "to recognize the geometric arrangements at appropriate length scales; to construct models that capture these arrangements; to populate them with appropriate small-scale properties; and to run flow simulations from which it is possible to determine the effective properties at the target scales" (Aplin et al., 2012). This approach also provides knowledge about the types of sedimentary and mechanical architecture that forms the critical controls, and the conditions under which these features affect fluid flow at chosen length scales. We have developed a set of techniques to recognize structural arrangements from core, well-log, outcrop, and seismic data, to construct constrained models from these observations, and to calculate effective properties by flow simulation.
Thermo-Dissoluble Polymer for In-Depth Mobility Control
Authors: Bai Baojun , Zhou Jia , Liu Yuzhang , Tongwa Paul
Published: May 2016

Gel treatments have been implemented as a cost-effective method for plugging high-permeability zones and thus improving sweep efficiency in reservoirs. However, when extensive cross-flows exist between formation layers, near wellbore gel treatments become less efficient. Polymer was used in polymer flooding to increase the viscosity of the injected fluids in order to improve the oil recovery. However, the efficiency of polymer flooding is limited by the dramatic viscosity loss (80–90%) caused by various shearing degradations during the polymer injection process and polymer transport at extremely high flow rates in near wellbore formations. This research focused on developing a novel polymer, which first is injected into fractures or fracture-like features as a millimeter-sized particle gel (50 um to a few millimeters) and acts as a plugging agent, and then dissolves into polymer solution at a designated time (e.g., 6 months) due to the reservoir's temperature; the dissolved polymer seeps into the depths of the formation to behave as a mobility control agent. The polymer dissolution process occurs under reservoir conditions, so the polymer's viscosity will not be influenced significantly by the degradations from pump, wellbore and near wellbore porous media. This paper will report the evaluation results of the new product. Several evaluation methods have been established to characterize the properties of the new polymer system before and after their dissolution. It has been found that the time it takes for the solution to dissolve depends primarily upon the reservoir temperature and liable crosslinker concentration. ESEM pictures revealed that the 3D polymer network of novel particle gel transformed into linear polymer after the polymer gel totally dissolved. Coreflooding experiments showed that the dissolved polymer exhibited excellent water resistance.
Successful Application of a New Electromagnetic Corrosion Tool for Well Integrity Evaluation in Old Wells Completed with Reduced Diameter Tubular
Authors: Zhang Shujing 'Peter' , Guergueb Nacer , Garcia Javier , Yateem Karam Sami , Sethi Neeraj
Published: May 2016

As the number of aging wells grows in the oil and gas industry, there is a recurrent need for monitoring the health of these wells over their productive life and providing assurance of the integrity of the well barriers that isolate them from uncontrolled formation pressure and fluids. Tubing and casing condition evaluation is a crucial aspect of this evaluation. The industry utilizes a number of conventional technologies for evaluation of tubing and casing integrity, such as internal mechanical calipers, electromagnetic and ultrasonic thickness (UT) tools, which are generally quite satisfactory for the evaluation of the inner casing but are often affected by internal tubular diameters in terms of their application. Most conventional tubular evaluation tools are unable to evaluate multiple concentric barriers. When combined with the low diameter production tubing completions the options for evaluating the production and outer casings become very limited, necessitating the need to pull the inner casing by performing a workover at a considerable expense and inspect the outer casing with conventional technology. A new electromagnetic casing corrosion evaluation technology was applied in a group of critical wells completed with small diameter tubing. The technology utilizes electromagnetic pulsed transient eddy currents to simultaneously inspect tubing and the casing behind it and provide quantifiably segregated measurements of thickness in the tubing and the first concentric casing as well as qualitatively characterized by a third casing string. This slim tool with a diameter of 1-11/16" allows measurements through slim production tubing. The objective of the study was to assess the integrity of a group of mature wells completed with small diameter restrictions, near populated areas and associated with high H2S environment. This study includes the candidate generation, field application, results evaluation and general recommendations for the well integrity program. The results exhibited that the data obtained from the tool is reliable. A quantifiable assessment of the metal loss of casing behind the tubing could be made, which made a mitigation strategy possible to prevent casing leaks, which in these wells are critical due to their population sensitive location.
Applying a Geologist's Tools to Decipher Scaling History: Integration of Mineralogy, Morphology, and Polymorphic Differentiation
Authors: Lynn Jack D.
Published: May 2016

Commonly, only very limited amounts (10–200 g) of sample can be retrieved by bailers or on the filter screens at well heads and the usual evaluation is simply XRD, XRF and occasionally, SEM analysis to identify basic mineralogy. Unfortunately, these very small and poorly differentiated samples are the only evidence production engineers have to evaluate significant issues with completion and drilling chemistry. But, a geologist's eye, and polymorph chemistry can use these small samples to dictate a story. In a recent study, meticulous sample preparation and visual sample evaluation, combined with XRD, thin section petrography, crystal morphology, and evaluation of polymorphic and formation water chemistry have been intertwined to evaluate scaling history in several wells in a high temperature, high pressure gas condensate field. The study was able to identify various polymorphs of CaCO3, (including Mg-calcite and aragonite), and assign them to quiescent vs. dynamic precipitation regimes, through the assessment of morphological features (including botryoidal, dendritic and flos ferri morphologies of aragonite). In addition, multiple stages of barium sulfate (BaSO4) and sulfate/carbonate co-precipitation were identified. An additional fecarbonate phase, siderite (FeCO3), was identified. Using thin section petrology, mineralogy, and a thorough review of drilling and completion operations, the unique scale formation history of these wells was traced, and issues were identified with long-term post-completion shut-ins while waiting for tie-in of manifolds to pipelines. Issues were identified with CO3 -2 pH buffers in formate based completion and drilling fluid interactions with high calcium formation brine, which migrates to the well bore by ionic diffusion and counter-current imbibition. The identification of this previously un-suspected damage mechanism has led to modification in completion fluid formulations to eliminate future events, and improve post drilling PI on wells drilled in the gas fields in question. It highlighted the requirement for a scale control program which is being developed to be concurrent with new well drilling and completion. Finally, the study highlights the need to evaluate fully the components of drilling, completion and stimulation fluids, both individually, and in combination-To be sure to fully assess the risk of formation damage, even when using a welltested and proven industry fluid. The phrase "doveryai, no proveryai" ("trust, but verify") takes on a new meaning (with due respects to US Pres. R. Regan).
Azimuthal Seismic Inversion for Shale Gas Reservoir Characterisation
Authors: Roure B. , Downton J. , Doyen P.M. , Michel L. , Souvannavong V.
Published: May 2016

Azimuthal AVO analysis can be split into two parts: the Amplitude Versus Offset (AVO) analysis and the Amplitude Versus Azimuth (AVAz) analysis. The properties of the Fourier transform allow these problems to be treated separately. If we calculate a Fourier transform of AVAz PP reflectivity data at a particular angle of incidence, we obtain Fourier Coefficients (FCs) that parsimoniously describe the AVAz and anisotropy, similar to the near offset Rüger equation. It is possible to attach physical significance to each of the FCs using simple rock physics models that relate the anisotropy to the fractures. The different FCs may be combined in a non-linear fashion to estimate fundamental fracture parameters including fracture intensity and orientation. The FCs are calculated using a limited range of offsets or angles, which places less demands on the data acquisition. This may be advantageous for 3D land data sets, where near offsets are particularly under sampled. However, reflectivity-based fracture characterization techniques show some limitations in terms of interpretation of the results. These limitations can be removed by using the azimuthal elastic inversion which provides layer properties that are easier to interpret and relate more directly to the geology.

Introduction

Ikelle (1996) and then Sayers and Dean (2001) demonstrated that it is possible to express the azimuthal AVO reflectivity response in terms of a Fourier series as a function of azimuth. Due to the orthogonality of the Fourier transform, these Fourier Coefficients (FCs) represent independent information and may be used in combination or individually to make inferences about fracture-induced seismic anisotropy. Fracture properties can be calculated using just one offset or angle of incidence and we can obtain results similar to those obtained by the near offset Rüger equation using multi-offset/angle data. Combinations of FCs may be used to obtain unbiased estimates of both the anisotropic gradient and the fracture orientation. The FCs and near offset Rüger methods share the same limitation that amplitudes are treated as reflectivities, i.e. the wavelet effect is still part of the solution. Moreover, the estimates are interface properties which are more difficult to relate to the geology than interval properties. To overcome these issues, Downton and Roure (2010) introduced an azimuthal elastic inversion where azimuthal angle stacks are inverted simultaneously. This method was later extended to invert azimuthal Fourier Coefficients (Roure and Downton, 2012). The fracture properties estimated by the elastic inversion can be more easily used for interpretation.
AKPO Condensate Field case study, Nigeria.4D seismic monitoring of a complex deepwater turbidite reservoir.
Authors: Piovesanel E. , Claudel G. , Atewologun A. , Adeyemi A. , Yuh S.
Published: May 2016

This paper addresses the 4D seismic monitoring aspects of AKPO, a complex deepwater field operated by Total Upstream Nigeria Ltd (TUPNI). AKPO development is driven by seismic in many ways. Seismic reservoir characterization is critical for well placement, optimization and monitoring while drilling, as well as to delineate reservoir sedimentology, capture heterogeneities and populate the geological model with rock properties. In addition, time-lapse seismic monitoring plays a key role in the understanding of the field dynamics, the update of the reservoir model and the field management as wells as the planning of the infill campaign. The first results of AKPO 4D monitoring program yield highly valuable information with great impact on reservoir management.
Study and Application of Shallow Water Fracturing Fluid in High Temperature Deep Carbonate Reservoir
Authors: Che Mingguang , Wang Yonghui , Cheng Xingsheng , Lu Yongjun , Li Yongping , Zhang Fuxiang , Peng Jianxin , Zou Keyuan
Published: May 2016

The Taklimakan is the second largest desert in the world; the TaZhong oilfield is located in the Taklimakan Desert heartland.

The Ordovician carbonate is one of the producing zones of TaZhong field. Acid fracturing has been normal for stimulating wells in these carbonate formations. The freshwater prepared for fluid and acid was conveyed 300 kilometers far away from TaZhong oilfield in the early construction, a lot of money and time was spent on transportation. However, there is superficial saltwater at a depth of tens of meters under the desert, and this paper will provide the technology of reducing freshwater consumption by using shallow saltwater for pad fluid in acid-fracturing.

First, this paper presents a brief developed history of TaZhong oilfield and the characteristics of Ordovician formation. In major, this paper introduces the study and case of Taklimakan desert superficial saltwater fracturing fluid, including the shallow water salinity tests and the problems of shallow water fluid, solutions for stable fluid and the performances of superficial saltwater fluid, such as the stability of saltwater fluid, rheology, and gel breaking and injures. Final, a field example of acid fracturing used shallow water fluid is included, and the responses of treating pressure are analyzed.

This work has helped prove the shallow saltwater in the desert of TaZhong oilfield which is feasible for service in acid-fracturing treatment oprations, a result has been established that a reliable fracturing fluid with good performance is wide used recent years. Because of the technology of superficial water fracturing fluid, an acid fracturing treatment well time saving is 2 to 3 days, and the transportation cost saving was considerable.

Introduction

The depth of the Ordovician formations is 4000m-6000m, and the temperature is from 110? to 150?. The natural fissures and vugs are major hydrocarbon reservoirs because of the low matrix porosity (2%-5%) and low permeability. Acid-fracturing is the main stimulating treatment in TaZhong carbonate, such as pad acid fracturing or multi-alterenative acid fracturing. Water based hydroxipropil guar fluids are generally used for preflush, and several acids are applied during treatment, such as gel acid, surface-crosslinked acid, emulsified acid and VES acid. Recent years, further development of the field had been achieved with well stimulations, increasing production rates, over a hurdred of wells were treated by acid fracturing and more than twenty wells were treated by hydraulic fracturing or sand fracturing with surface-crosslinked acid. This has led to increase freshwater consumption for these oprations, in order to save freshwater sources and conveyance costs, the field employers have to find alternatives to reduce the fresh water consumed, the shallow saltwater under the Taklimakan desert is considered.