bluuebunny/crossref_metadata_2025 huggingface dataset:
Fault Detection Workflow In Al Khalij Field In Qatar
Authors: Klein Blandine , Gauthier Bertrand , Mccallum John , Emang Michael Ipui
Published: May 2016

In Al Khalij carbonate field, the impact of faulting and fracturing has long been considered insignificant on the dynamic reservoir behaviour. However with the continued field depletion, an interference between some wells has been noticed. This interference cannot be explained by matrix properties. Therefore, a better understanding of the detailed structure grain seems to be the key for understanding the field dynamic behaviour. This integrated study shows that faults can barely described from the seismic data. But it has been found that a detailed understanding of the field structure is possible if other data are also taken into account.

The model was therefore constraint with an integrated approach developed along the following four aspects:1. Structural interpretation of the horizontal wells;2. Seismic attribute analysis;3. Image log data analysis;4. Dynamic data analysis.

The structural interpretation of the seismic fault lineaments and the well fracture systems suggest that they are related to two successive compressive tectonic phases of different orientations which are controlled by a deep structural heritage and which result in a strike slip (transtensive), structural style.

A new structural model (Geo model) was created, but because of the insufficient reliability of the lower reservoir markers, a special attention was paid to the layer thickness construction. A meticulous structural study and the fault throw distribution analysis were performed before the final structural model construction to validate the structural consistency of the interpretation. All this work performed in 2D resulted in a very consistent structural network which was then used to define the 3D grid.

This geomodel reconciles all available data and analyses and gives a much more geological image of the field structure.- Layer thicknesses are homogenous and not affected by drastic changes close to well calibration points.- The resulting fault network appears to be rather predictive from recently drilled wells.

This new model will be the base of an updated reservoir model which should give a much better qualification of the field dynamic behaviour as investigated by other specialists.
Skin Calculation and Other Applications with New Sonic Measurement in the Gulf of Thailand
Authors: Jiang Long , Pabchanda Suwit
Published: May 2016

Since the first sonic logging tool used for the petroleum industry in 1950s, we have seen many generations of acoustic measurements. The hardware and software changes made over the decades focused mainly on the improvements of compressional and shear measurements which are one dimensional in the near-wellbore region. To understand the complicated reservoirs today, there is a need to look at the compressional and shear slowness in three dimensions.

The present wireline sonic logging tool that is equipped with a long receiver array and near and far monopole transmitters enables us to quantify the compressional slowness of near-wellbore damaged formation and the far-field undisturbed formation. This radial measurement adds an extra dimension to reservoir characterization.

The compressional radial profiling clearly shows the formation damage across part of the reservoir. By combining it with the pressure drawdown mobility taken from undamaged and damaged zones, one can, for the first time, measure the mechanical skin just after drilling. The information is available at the wellsite. It helps to optimize the real-time data acquisition and completion selection.

The fluid identification is one of the challenges in the deeply invaded reservoirs. The depth investigation of new sonic measurement is much deeper than conventional neutron density logs and previous sonic logs. Other applications including gas detection in deeply invaded reservoirs provided unique solutions in the Gulf of Thailand.

The field example also demonstrates an enhancement in vertical resolution with the multiple-shot processing technique. This is much needed for evaluating the thin reservoirs.

Introduction

Traditionally, the total skin is calculated by well tests. The limitation is that the well tests do not measure the individual skin parameters. The methods for calculating the skins are well documented in many papers. Pucknell and Clifford (1991) discussed various methods. However, there are many assumptions, including the radius and permeability of the damaged zone.

The mechanical skin caused by drilling and perforation is one of the most difficult skins to measure. While the modern perforation technique can reduce or eliminate the perforation skin, the drilling damage remains the same.

In this paper, a new method for evaluating the drilling damage is introduced. It uses the new sonic data which provide direct measures of the formation damage (or alteration) radius.

Methodology

The principles and applications of the new 3D sonic measurements are well documented in Pistre et al. (2005). Compressional radial variations are determined by evaluating both the short- and long-spacing monopole measurements. Short spacings probe the formation in the near field (shallow), whereas longer spacings probe the formation in the far field (deep). This is graphically represented in Fig. 1.
Developing New Petroleum Engineers in a Non-Operating Environment
Authors: Ibrahim Mohd Isa , Almuhanna Ali Ibrahim , Amiri-Garroussi Kourosh
Published: May 2016

The paper will briefly explain aspects of career development for a new young engineering graduate to become a petroleum engineer in an international subsidiary of a National Oil Company in a non-operating environment.

Developing a new graduate into a petroleum engineer is a challenging goal to achieve, especially in a non-operating company environment. The essential well-site and field operational knowledge/experience is hard to obtain. Therefore, a simple approach is adopted as an initial 2-year training stage in order to capture the basic petroleum engineering hands-on experience required for the young engineers that require continuous assistance.

The development scheme is adopted by the company to accelerate the placement of local graduates in various technical positions, in order to support senior petroleum engineers. It consists, among others, planned work programs, daily tasks, formal training courses locally and internationally, on-job-training, conduct ad hoc focused assignments and projects, getting exposure to operational sites and further study on part-time degree course.

The development scheme has yielded positive results. Many young engineering graduates have excelled in their careers to higher levels within a few years, however exception also exists.

The development scheme will continuously be improved to an in-depth focused development program that will capture more operational knowledge and experience. Hence, it will generate skilled and knowledgeable young professionals to operate and manage oil and gas companies.

Introduction

KUPFEC is one of the many subsidiaries of Kuwait Petroleum Corporation (KPC). There are four subsidiaries which are involved in upstream exploration and production of oil and gas - KUFPEC (Kuwait Foreign Petroleum Exploration Company) engages in international foreign onshore/offshore exploration & production, mainly as a non-operating Joint Venture Partner, while the other three engage in the domestic and nearby acreage exploration / development / production.

KUFPEC's global assets stretch from West Africa to Far-East and from Australia to the North Sea. KUFPEC's 2030 strategy consists of the following:• To achieve targets set by KPC for crude oil and gas production & reserves increases.• To give preference for investments which facilitate transfer of know-how.• To achieve & maintain optimal ratio of upstream oil and gas.• To become an operator of international upstream assets.
Application of Permanent Reservoir Monitoring Data (DTS* & PDG*) in a Mature Offshore Malaysian Oil Field, for Production Optimisation and Workover Control
Authors: Goh Kim Fah Gordon , Gee Michael Joseph , Zaini Muhamad Zaki , Molavi Saeed , Salim Muzahidin Muhamed
Published: May 2016

Permanent Downhole Reservoir Monitoring and Surveillance is becoming fundamental for optimal reservoir management, without the requirement to re-enter the well. In order to identify zonal allocation from multi layer reservoirs, DTS and zonal PDG data have been integrated to provide a cost effective alternative to conventional wireline logging (e.g. PLT), thereby mitigating oil deferment and intervention risks.

This paper demonstrates the approach taken by integrating DTS and PDG data with reservoir petrophysics, to interpret reservoir inflow performance, to maximize the benefits of a successful workover, by increasing oil production and decreasing water-cut. A field case from offshore East Malaysia will be shown, demonstrating the following benefits:1. Zonal inflow profiling and trending from DTS data interpretation2. The effective use of PDG data to calibrate DTS-derived flowing BHP during zonal flow profile interpretation, has improved interpretation accuracy3. Increased oil production from the workover with zonal SSD changes, using the interpretation results of integrating DTS and PDG data, in order to reduce surface water production.4. The value of permanent DTS during initial completion pressure testing, to identify leak paths along production tubing, thus saving rig time and remedial leak-detection intervention.5. The advantages of permanent downhole monitoring against alternative of conventional PLT intervention.

Throughout the DTS and PDGs deployment, the data acquired has been reliably used to assist future production strategy and reservoir management. The availability of zonal pressure and rate contributions derived from DTS and PDGs data, has allowed optimal reservoir layer drawdown, to mitigate the effects of potential sanding, which is the only well in the field that has been completed without the normal field practice of gravel pack.

The retrieval of fiber-optic temperature data and PDG pressure measurements is unlimited, enabling rapid production diagnostics without the need for production deferment. Hence, a cost-effective data acquisition over the well life is achievable which has improved the analysis of zonal comingled production in multi-layer reservoirs and guided the future zonal workover control.
Exposure to Phosphate-based Completion Brine Under HPHT Laboratory Conditions Causes Significant Gas Permeability Reduction in Sandstone Cores
Authors: Downs John David
Published: May 2016

High-density potassium phosphate and potassium/cesium formate brines were tested in an advanced core flood test rig for their compatibility with low-permeability sandstone containing simulated formation water under HPHT conditions. The tests were carried out at a temperature of 175oC (347 oF) and pore pressure of 5,800 psi. Compatibility was determined by comparing the relative gas permeability of the cores before and after exposure to the brines under HPHT conditions.

The 10–20mD sandstone core plugs, containing simulated North Sea HPHT gas reservoir water at residual water saturation, were flooded with 10 pore volumes of test brine and subsequently equilibrated with the brine for 48 hours to allow chemical interaction. Drawdown pressures of up to 100 psi were then created on the wellbore side of the core to create gas flow. Gas permeability was measured after flowing 4,000 ml (approx. 2,000 pore volumes) of humidified gas through the core. The results showed that flooding this core with the potassium phosphate brine reduced the gas permeability by more than 90%. By comparison, flooding with cesium formate brine created a modest improvement in the permeability of the core to gas.

Examination by SEM of the core damaged by the phosphate brine showed that its pores were partially obstructed with a thick layer of scale. The scale was particularly plentiful in areas of the core where illite clays were present. The scale was examined in situ by EDS and found to contain potassium and phosphorus. It is known that phosphates in aqueous solution are strongly adsorbed onto mineral surfaces where they can form precipitates and complex insoluble salts from exposure to multivalent cations. Aqueous phosphate solutions are also known to react with clays to form solid precipitates. It is possible that the scale formed in the core as a result of interactions under hydrothermal conditions between the invading phosphate brine and, inter alia, the pore-lining illite clay deposits naturally present within the rock.

The scale modeling software, DownHoleSAT, predicted a significant risk of various phosphate scales being formed as a result of mixing of the formation water and phosphate brine inside the core under the experimental conditions. Such scales may have contributed to the formation damage observed in the core flooded with the phosphate brine.
Implementation of Next Generation Intelligent Downhole Production Control in Multiple Dipping Sandstones Reservoirs, Offshore East Malaysia
Authors: Chen Jiun Horng Chris , Nuriyadi Mohd Azrul , Bakar Mohd Farris , Kamarul Zaman Nur Hazrina , Aminuddin M.K. M. , Mohd Yusoff Saiful Anuar , Goh Kim Fah Gordon , Gill Premjit Kaur , Luke Darren , Ahmad Eddep
Published: May 2016

The 'S' field, located offshore East Malaysia, consists of multiple-dipping heterogeneous sandstone reservoirs with unconsolidated formation. These multi-stacked reservoirs have an overall 40m thick oil column with marginal Oil-Initial-In- Place (OIIP). A large gas cap, i.e. twice the OIIP equivalent, also exists. Scenarios of zonal gas-out leaving huge oil bypass and moderate aquifer strength with inevitable water invasion cautioned the asset team to consider intelligent zonal flow control especially in its horizontal producing wells.

Two of the 14 horizontal producer wells in this marginal field have been screened to apply the modular integrated intelligent completions system (IICS) to actively control and permanently monitor zonal inflow for optimal production. Future selective production control and data surveillance enabled by the IICS are essential to fulfill the needs for delicate downhole zonal flow balance for ultimate oil incremental and recovery. It provides control against the aggressive gas cap expansion at the heels while addressing the moderate aquifer coning-up problems from the dipping toes as the field depletes.

This paper highlights the successful implementation of the next generation intelligent completions system in a complicated, highly-dipping, multi-layered sandstone reservoir with commingled production. In this multi-zonal production solution, the conventional surface-controllable downhole zonal flow control valves are now integrated with data surveillance gauges, intelligent sensors and isolation packers all into one single completion joint, instead of the precedent multi-joints system (i.e. splicing required up-to 3 joints per zone conventionally). This single modulated joint system has reduced installation time substantially in comparison to conventional intelligent completions installations. The risk of surface completions make-up damage before run-in-hole is also greatly reduced with less connecting components. This robust yet compact system has made on-site completions tally adjustment easier and is enabled with LWD data update while drilling. As a result, intelligent completions design becomes more flexible and responsive to actual reservoir challenges and drilling surprises - providing an all together "intelligent" solution.

This paper also discusses the screening process from simulation performed for candidate evaluation to the resulting impact on production post-installation. Future applicants of such technology with similar fields' nature and risks can benefit from the discussed lesson-learnt; best-practice workflow and seamless teamwork and coordination between the project team and service providers in delivering an advanced fit-for-purpose solution.
Evaluation of Time-Domain Controlled-Source Electromagnetic Method for Detecting Hydrocarbon Targets in East Malaysia Environment
Authors: Fuad M. Izzuljad Ahmad , Bujang Awg Amirul Zakry Awg , Majid Hani Noorashiqin A. , Rahim M. Faizal Abd , Meju Maxwell Azuka , Arshin Boshara Merghani
Published: May 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

The time-domain Controlled Source Electromagnetic (tCSEM) method is emerging as a practical tool for oil and gas exploration on land and shallow marine environments (Wright et al., 2002; Ziolkowski et al., 2007). In particular, it can overcome the airwave interference problem faced by frequency-domain CSEM method in shallow water (Weiss, 2007). We have used a 1D broadband tCSEM inversion technique developed in-house. The forward problem is solved using the algorithm of Edwards (1997) while the inverse problem is solved using a variety of nonlinear parameter estimation methods (Meju, 1992, 1994). The inversion method generates either blocky sharp-boundary model or the smoothest model that fits the data recorded for different offsets and various transient times. In this work, a layered-earth resistivity model was constructed using the local borehole resistivity log and served as the test model (ground-truth). The parameters of this model were systematically varied and used to generate forward model responses enabling us to determine the effect of target depth, thickness and resistivity variations. The synthetic data for the ground-truth model were finally inverted to test the detection capability of tCSEM.

The aim of our research was to evaluate the applicability of tCSEM technology in East Malaysia environment by studying the effect of target and water depth, target thickness, target resistivity variation, and target detection limits using a combined numerical modelling and inversion approach.

The results of modeling and inversion studies suggest that the tCSEM method is capable of detecting hydrocarbon reservoirs in East Malaysia environment. The inversion responses become more significant when dealing with thick, strong resistivity, and shallow marine hydrocarbon target. From the case of target depth variation, the inversion responses capable to distinguish hydrocarbon target at difference depth.

From this study, we capable to investigate in detail about the strength and limitation of this method in East Malaysia environment and this beneficial information can become a guideline for future feasibility study and tCSEM survey planning. Furthermore, this method also can be used as an alternative method to provide technical solution and reduce exploration risk especially in shallow marine environment.
New Phase of Formation Evaluation in the Gulf of Thailand
Authors: Duangprasert Tanabordee , Daungkaew Saifon , Paramatikul Ronarong , Vincent Regis
Published: May 2016

The Songkhla field in the southern Gulf of Thailand was put on production by CEC International (Thailand) in early 2009. As with any relatively small field development, it was important to optimize capital investment and formation evaluation technologies selected in order to minimize risk and total cost by making the proper field development decisions.

Formation evaluation is challenging in this field where fresh formation water, laminated shaly sands, low gas-oil-ratio (GOR), waxy oil, and low permeability are all present. This environment causes low contrast in formation resistivity between oil and water, making log analysis difficult. Small errors in clay volume and porosity have such a large impact on the resulting saturation computation that it is sometimes difficult to compute an accurate saturation or even determine if the zone is hydrocarbon bearing. Variable oil viscosity and permeability also make development planning especially difficult.

This paper aims to demonstrate the challenges of formation evaluation in such reservoirs and the uses of new formation evaluation technologies to help overcome these issues from number of wells in Songkhla basin. Several acquisition technologies have been introduced to improve the formation evaluation:(1) A new Downhole Fluid Analyzer (DFA) tool has been developed to enable evaluation of low GOR oils, and to conclusively identify the formation fluid, zone by zone, and to optimize completion selections.(2) A high performance dual packer module was combined with the new DFA technology to evaluate the feasibility of developing lower quality parts of the reservoirs.(3) A cased hole formation tester was deployed to identify reservoir fluid identification in one particular zone where the reservoir fluid was not conclusively determined when the well was first evaluated.

Songkhla Field background

Since late 2008 CEC International (Thailand) Ltd (formerly NuCoastal Thailand Ltd) has drilled more than 30 wells in the Songkhla Basin. To date approximately 4mm bbl crude have been produced from reservoirs of lower Oligocene, Miocene and Eocene age using using electric submersible pumps (ESPs) and a mobile offshore production unit (MOPU) with crude piped to a tanker. The Lower Oligocene reservoir is typically at around 8000ft TVDSS and has porosities in the range 18- 20%. The produced oil is a medium sweet grade with an API gravity of 29° and a low GOR of around 100 scf/bbl.

Formation evaluation is challenging in this field due to the presence of fresh formation water, laminated shaly sands with low permeabilities. The resulting low contrast in formation resistivity between oil and water makes the identification of water saturations and oil pay difficult. In this context a number of formation evaluation tools were used to better understand the nature of the fluids.
3D-VSP and Surface Full-azimuth Seismic Integrated Study in Daqing Oil Field
Authors: Li Yanpeng , Ling Yun , Chen Yuanzhong , Gao Jun , Xu Gang , Chu Fangdong
Published: May 2016

Along with the progress of VSP techniques, especially the improvement of downhole geophone manufacture and VSP data processing methods, now the survey mode has developed from zero offset VSP, offset VSP to Walkaway-VSP, Walkaround-VSP and 3D-VSP corresponding to different geological objectives. VSP techniques have obtained partial success in parameter estimation, high precision imaging and reservoir characterization, but obtained dataset is range limited and imaging still need to be improved. In order to broaden the range of survey and expand the advantages of VSP to surface seismic, large array 3D-VSP and full-azimuth surface seismic survey were carry out in XJWZ area of Daqing oil field. The reservoir of this area is mainly formed by volcanic and its distribution is very complex due to many periods of volcanic overlap in this area. Previous seismic surveys are mainly 2D and narrow azimuth 3D, the results still cannot be used for anisotropy analysis and fracture discrimination effectively, say nothing of satisfying the requirements of developing plan establishing. So a joint survey of 3D-VSP and full-azimuth surface seismic was implemented. This project tries to combine the advantages of VSP and surface seismic, measuring in borehole and surface simultaneously. Thus, real three-dimensional survey was achieved. Some comprehensive studies are presented in this paper, these research work include: 3D-VSP and full-azimuth surface seismic simultaneous survey design; Q factor and anisotropy parameter estimated from VSP and applied to 3D seismic processing; characterize reservoir and predict gas saturation with final images. The interpreted results have been used for well drilling and wet gas has been founded, so the validity of this method has been proved.

Introduction

The work area studied here is located in northeast part of China. Objective is a gas-bearing volcanic reservoir. The formation and distribution of volcanic reservoir in this area is extremely complicated (Figure 1). It is shown in early-stage study that the YC Formation in this area is characterized as a very complicated vertically superimposed structure due to numerous volcanic eruptions (Figure 2). Volcanic rock holds a sensitive spatial variation in its lithofacies. In the past, only the 2D and the narrow-azimuth 3D surface seismic surveys were carried out in this area, which have a certain limitation in identifying the anisotropy of volcanic rocks and the fracture zones, and therefore can not meet the requirements on working out the development program for the oil field at latter stage.
Predicting Marginal Marine Reservoir Architecture: Examples from Asian Shoreline Systems
Authors: Ainsworth Bruce , Vakarelov Boyan
Published: May 2016

Sequence stratigraphy is often used to link coastal depositional style to specific systems tracts. Even though such an approach has merit, it is argued that other variables, such as basin setting, distance from a shelf edge, local physiography and shoreline shape are more useful for predicting shoreline architecture, especially when it comes to the effects of waves and tides. This is because shorelines in different systems tracts can be exposed to similar combinations of processes, which have a first order dependence on the shape of the marine basin fronting them.

To test the above hypotheses, we performed process-based analysis of 416 modern marginal marine systems from Asian coastlines, which show large variability of basinal, shelfal and local coastal physiographic conditions. Each system has been characterized in terms of architecture and basin setting, which can then be compared.

Architecture is defined using a check-list of geomorphologic criteria such as presence of beach ridges and beach ridge sets, presence of tidal channels, degree of tidal funneling visible at the mouths of fluvial channels, presence of tidal flats, measure of lobateness of the shoreline, among others. Using such criteria, the systems have been placed into one of fifteen process classification categories from defined by Ainsworth et al., (2011) (W; Wt, Wf; Wtf; Wft; T; Tw; Tf; Twf; Tfw; F; Fw; Ft; Fwt; Ftw) that reflect the relative impact of wave (w), tide (t), and fluvial (f) influence at a shoreline.

Basin setting parameters describe whether a system occurs on a narrow shelf (<75km), wide shelf (>75km), small embayment (<50km), large embayment (50–500km), a seaway (>500km), a combination of these, as well as additional parameters describing levels of shoreline protection (partially protected; protected; enclosed).

The results of the study show statistically significant, probabilistic relationships between basin setting and process classification which can potentially be used in a predictive manner in the subsurface. It is shown that over 90% of systems on narrow shelves belong to one of the wave-dominated categories (W, Wf, Wt, Wft, Wtf), with the vast majority of these belonging to the W and Wf category. It is also shown that the wave-dominated proportion significantly decreases on wide shelves, large embayments and continental seaways, where wave-dominated systems occur only 55–65% of the time, with tide-dominated and fluvial dominated systems becoming proportionally more important. Such systems also show overwhelming dominance of mixed influence categories. This is important since the mix of process influences results in increased heterogeneity in the systems. This then escalates the risk of stratigraphic reservoir compartmentalization in the subsurface.
Karst Modeling of a Miocene Carbonate Build-up in Central Luconia, SE Asia: Challenges in Seismic Characterization and Geological Model Building
Authors: Chung Elvis Kang Yeu , Ting King King , AlJaaidi Omar
Published: May 2016

The development of the Central Luconia carbonate build-ups were strongly influenced by the interplay between eustatic sea-level and basinal tectonics. The Alpha field addressed here is one of the seismically best imaged isolated carbonate platforms in Central Luconia and dendritic features, interpreted as karst, were found to be very prominent throughout the field. Karst is a diagenetic facies, an overprint in sub-aerially exposed carbonate bodies produced and controlled by dissolution and migration of calcium carbonate in meteoric waters. The exploration well in the Alpha field encountered total losses while drilling which was believed to be as a result of drilling in to karst (common in Central Luconia carbonates). Some of the best features from Petrel, Landmark and Shell software packages have been integrated to generate an attribute volume for karst interpretation. Using Petrel Geobody, multiple 3D box probes with short time gate and optimum clipping value were used to extract the karst Geobodies. Using a short time gate box probe is crucial for CPU/memory performance and most importantly, to have better control on editing noise and non-karst signal later.

Karst has a big impact on well planning (problem with losses and completion length), the hydrocarbon volume in-place as karst provide substantial secondary porosity; and well management and development strategy (wells nearer to karst are more likely to water-out quicker). This study incorporated an integration of well data, seismic characterization and geological understanding of the field and near-by analogues in building a subsurface model for field development.

Geology

The Central Luconia Province is located in offshore NW Borneo. The province is delineated by two major strike-slip faults, the West Baram in the northeast and the Rajang line in the southwest (Figure 1). Seafloor spreading in the South China Basin during the Oligocene to middle Miocene resulted in formation of a horst graben system that which controlled distribution of subsequent reefal carbonate growth. At mid-late Miocene reefs developed preferably on horst blocks (Mohammad Yamin Ali & Abolins[1]). Two major factors controlling carbonate sedimentation in the Central Luconia province are the regional tectonics and eustatic sea level changes. Tectonics played a role in creating horst and graben structures which served as basement for the onset of carbonate deposition and exerted an influence on the size and shape of the build-ups (Ting et al[2]). The latter also dictated the type of the depositional facies and their distribution which governed the reservoir properties of the carbonate platform.
Study and Application of Carbonate Reservoir Characterization in Block-B on Eastern Margin of Pre-Caspian Basin
Authors: Chen Hongtao , Li Jianying , Yang Feng , Li Yibao
Published: May 2016

Carbonate sedimentary facies division and reservoir prediction are the problems that have obsessed the petroleum industry for many years. Combined with the regional sedimentation evolution background of Block-B on the eastern margin of the Pre-Caspian Basin and reservoir features dominated by primary porosity indicated by drilled well, this paper performs the stratigraphic sequence division under the carbonate platform sedimentation background firstly, and secondly, performs division and optimization of seismic facies and sedimentary microfacies within different system tracts, and indicates that tidal flat and dolomite flat microfacies of restricted platform subfacies within the high system tract of sequence KT-I are the most favorable reservoir development facies in Block-B. Based on fine correlation and calibration of system tract, qualitative and semi-quantitative prediction are performed for reservoir planar distribution within the favorable reservoir facies with adoption of multiple geophysical methods such as seismic attribute analysis and well logging constrained inversion. Drilling exploration is implemented for TLW structure by overlapping structural mapping result, high yield hydrocarbon flow is acquired and TLW large-scale oil and gas bearing structure is observed, which is the largest discovery of Kazakhstan land exploration in the past decade. Drilling result has verified the reliability of the study.

Introduction

Block-B is located to the southeast of Zhanazhol Oilfield, Aktoube State, the Republic of Kazakhstan, and structurally is located at the slope of transitional zone from the Astrakhan-Aktubinsk uplift to the southeast depression zone (Figure 1). During the Hercynian orogeny, the block uplifts integrally at later stage, which is the final directing zone of oil and gas migration with quite favorable regional structural position.

At present, the drilled results in the study area confirms that carbonate rock of Carboniferous system are the main target layers of the working area, and have obvious anisotropism. Due to the quick lateral variation of the reservoirs, it is very difficult to predict. Therefore, the improvement of reservoir prediction accuracy is one of the key factors for acquiring successful drilling.
Seismic-While-Drilling Checkshot Survey on High-Inclination Well-Beyond the Time and Depth
Authors: Ahmed Aqil , Lim Teck Kean , Wuertz Walter , Kanaree Maneerat , Pirie Wayne Scott , Rebel Pieter
Published: May 2016

In many drilling environments, recording checkshots using logging-while-drilling (LWD) services mitigates drilling risk by obtaining time-depth information to position the drillbit on the seismic map. In high-inclination wells, acquiring these data can be both time-consuming and problematic. Seismic while drilling, however, faces the high-deviation challenge without additional rig time. It can be used beyond the time-depth application by using recorded waveforms as vertical seismic profiling (VSP).

A drilling campaign offshore West Malaysia included several development wells (J and S types). As these wells were on the edge of the field, checks hot information was required to confirm the existing velocity model for the area. Uncertainty in the velocity model was caused by the presence of shallow gas clouds. By applying seismic-while-drilling technology and running it in the LWD bottomhole assembly (BHA), seismic checkshots were acquired while tripping out of the hole. This procedure was completely transparent to drilling operations, as shots were acquired only during pipe connections.

The seismic source wavelet was produced by a 3×150??in.3 sleeve air gun array deployed from the survey vessel. Although the tool has no active coupling, the high wellbore deviation ensures adequate coupling between the sensors in the BHA and the formation. Survey and connection information was transmitted sing ultrahigh-frequency (UHF) radios, and dedicated navigation ensured the vessel was on station ahead of time. The checkshot data agreed well with the predicted model and provided a useful verification of its validity. The recorded waveforms produced an image with higher resolution than the surface seismic below the well path for reservoir delineation. Also, seismic phase and time matching between the corridor stack and the surface seismic were conducted to characterize the embedded seismic wavelet and assist with reservoir interpretation.

Overview

Acquiring checkshot data can be both time consuming and problematic in high-inclination wells using conventional wireline methods. With the advent of seismic while drilling, we can now eliminate these problems and efficiently acquire checkshot data in highly deviated wells.

This case study demonstrates the practical application of existing seismic while drilling technology to reduce both time and cost to the client in acquiring a vertical incident VSP (VIVSP) survey offshore Malaysia.
Hybrid Power Generation for Offshore Wellhead Platform: A Starting Point for Offshore Green Energy
Authors: Rongsopa Roongwit
Published: May 2016

The purpose of this paper is to present the DC power supply for unmanned remote wellhead platforms (WHP). In several recent WHP projects, there are a number of difference aspects in Bongkot and Arthit Fields in the PTTEP's Gulf of Thailand and one of them is the DC power supply. PTTEP by Wellhead platform department intends to standardize the design of DC power generation for Generic Wellhead Platforms (Generic WHP) for either Bongkot or Arthit fields.

Offshore wellhead platforms have been powered by various power generation technologies such as Gas engine generator, Diesel engine generator, Closed cycle vapor turbogenerator (CCVT), Thermoelectric generator (TEG) including renewable energy technologies such as Solar power system and Wind turbine generator. Both Solar power system and TEG are widely used as DC power generation for offshore remote wellhead platforms to power platform DC loads such as PLC, SCADA, and Radio system.

Technical evaluation for various DC power supply will be presented. The scope of this paper is to discuss and recommend the most suitable DC power generation configuration for the Generic Wellhead Platforms focus on techno-economic with consideration of optimum point of reliability, economy, and environment.

In addition, all calculations of system equipment sizing for the selected DC power generation configuration for generic WHP will be detailed in this paper.

1. Introduction

The existing wellhead platforms (WHPs) of PTTEP in Bongkot and Arthit field are equipped with various types and configurations of DC power generation system. The Bongkot WHPs in old phase (e.g. phase 3E, 3F and 3G) are equipped with Closed Cycle Vapour Turbogenerator (CCVT) as main DC power generation, while the recent development Bongkot WHPs phase 4A are equipped with Thermoelectric Generator (TEG). The TEG system has been also installed in Arthit WHPs phase 1A (i.e. AWP 2–6). During design development for Arthit WHPs phase 1B (i.e. AWP 7–10), the Solar & TEG hybrid DC power system was first introduced and implemented as main DC power generation system for PTTEP WHPs in order to improve platform power availability and reliability. The Solar & TEG hybrid DC power system has been continuously used for recent Arthit WHP development project such as Arthit North project.
Gas Flare Reduction Through Operational Enhancement and Innovative Modification & Projects
Authors: Al-kandari Ali Hussain , Veeraraghavan Ashok Kumar , Saqeq Omar Ali
Published: May 2016

Description:Kuwait Oil Company (KOC), over the past few decades has significantly increased the Oil production to meet the ever increasing global energy demand. In this process, the production of associated gas has also gone up many folds, surpassing the Gas handling & exporting capabilities. KOC-West Kuwait(KOC-WK), surface handling capacity expanded by three folds in 2001 while the associated gas handling facilities was short of requirements due to improper gas production estimates. This resulted in significant gas flaring, more than 70%, leading to substantial revenue loss and environmental impact.

Application:KOC with its commitment to corporate & social HSE performance has demanded KOC-WK to bring down the annual flaring targets to 1%. Accordingly, Flare reduction road map was drawn with short term and long term plans to meet the company flaring targets. Some of the quick wins were a) Improving operational efficiency of equipments & operating crew, b) Identifying imbalance in gas handling capacities and redistribution among facilities. c) Improving Gas export quality through continuous operation of dehydration & refrigeration system. Some of new projects planned and being executed are a) Centralized Gas Booster station b) Additional transit lines, slug catchers c) Gas sweetening & Gas re-injection facilities at KOC, d) Capacity redundancy of AGRP plants.

Results:The short terms measures were completed by 2009 resulting in flare reduction from 70% to 12.5%, while the long term initiatives will ensure the flare reduction to 1% by 2013–14 and meet the company targets.

Significance of Subject Matter: The Key initiatives which brought about the flare reduction were internal modifications, incorporation of latest technology in new projects, increased awareness among operating crew and establishment of effective coordination and monitoring systems.
Design, Implementation and Performance of a Down-Dip WAG Pilot
Authors: Choudhary Manoj Kumar , Parekh Bimal , Dezabala Edward , Solis Hector Arturo , Pujiyono Pujiyono , Zambrano De Narvaez Judith Zambrano
Published: May 2016

Water-alternating-gas (WAG) injection is an enhanced oil recovery (EOR) method aimed at increasing sweep efficiency by contacting zones that are not adequately swept by water injection and by increasing microscopic displacement efficiency as gravity-aided WAG injection often gives lower remaining oil saturation. WAG performance also depends on whether it is updip or down-dip injection. Most WAG case studies available in the literature are up-dip WAG injection and most fields with WAG are in North America. This paper will present a case study of down-dip WAG in a field offshore West Africa. Field E is located offshore West Africa. Production from the gently dipping reservoir started in December, 2006 with peripheral water flooding as a primary recovery method. A WAG injection pilot was implemented in a down-dip injector in June, 2009. The main motivation for WAG injection was to reduce gas flaring with a secondary objective of improved oil recovery. Design, implementation and surveillance of the WAG pilot required a multi-disciplinary approach. Coordination between the subsurface and the operations teams was key to ensure timely implementation of the WAG pilot as per the design including subsequent data gathering.

For WAG pilot design, a full-field simulation model was built and history matched. Sensitivity runs were made to optimize fluid injection rates and WAG cycle size to reduce flared gas volumes without having a negative impact on recovery. Conversion of a down-dip water injector to WAG required minimal facilities modifications. A comprehensive reservoir surveillance plan was developed to monitor WAG performance. Surveillance results to date indicate down-dip WAG is having a positive impact. Based on encouraging results and on updated simulation modeling, the WAG pilot has been expanded to another injector. The paper will discuss details of down-dip WAG pilot program design, implementation, surveillance and performance.

Introduction

Field E was discovered in May 2001. The exploration well encountered oil-bearing turbidite sands of Campanian (Upper Cretaceous) age. To date several exploration and appraisal wells have been drilled in and around the area, identifying multiple, normally-pressured hydrocarbon accumulations.

Field E is located on the present day continental shelf in ~65 m of water at an average reservoir depth of 1,000 m. Seismic mapping (Figure 1) identifies two meandering canyons. The North-East canyon (E canyon) is where Field E is located. It is a gently dipping reservoir with dip angle varying from 5º to 10º. A cross-section through Field E is shown in Figure 2. There are several mapped faults. Based on the field performance, these faults are acting as baffles to fluid flow. Trapping in Field E is primarily stratigraphic with some local structural fault intersection closures.
Comparison of Fluid Prediction Success between AVO and Bright Spot Techniques in the Marco Polo Field, the Gulf of Mexico.
Authors: Suwannasri Krongrath , Tatham Robert H. , Spikes Kyle
Published: May 2016

Bright spot amplitude anomalies in seismic data are common indicators of natural gas; however, an interpretation based purely on these amplitude anomalies often yields a false indication of gas-saturated sands. A data set from the Marco Polo field, the Gulf of Mexico, demonstrates this problem. A discovery well was drilled into a sequence of bright spot anomalies that were indeed gas-saturated sands. This suggested that other bright spots in the seismic section also corresponded to gas sands and that non-bright spots were to brine-saturated sands. Nine development wells were later drilled into those bright spots, but not all of them were gas sands and not all of non-bright spots were brine-saturated sands. This study utilized Gassmann fluid substitution and three seismic amplitude versus offset (AVO) techniques (intercept and gradient, elastic impedance, and Lambda-Mu-Rho) as a comparison to purely using bright spots technique for fluid-type prediction at the location around the discovery well. This study used borehole information only from the discovery well in the purpose of AVO calibration. Forward models for the three AVO techniques were created from the well-log information in order to predict differences in the modeled attributes between gas- and brine-saturated scenarios. Pre-stack seismic data were inverted for intercept and gradient attributes, elastic impedance (EI) volumes, and Lambda-Mu-Rho (LMR) volumes. These volumes were compared to the forward models to predict gas- and brine-saturated locations. The prediction results were evaluated with information from the nine development wells. The intercept and gradient, elastic impedance, and LMR techniques yielded correct predictions of 52%, 61%, and 70%, respectively, of the observed sands. The traditional bright spot method yielded only 45% of correct fluid prediction. In conclusion, the pre-stack AVO techniques provided a better fluid prediction than relying solely on the post-stack bright spots alone. Furthermore, the prediction results improved as the computational intensity of the inversion increased from the intercept and gradient, to the elastic impedance, and to the LMR technique.

Introduction

Bright spot and its pitfall.

The use of bright spot seismic amplitude anomalies to predict the location of petroleum resources has increased over the past four decades; however, this technique can be unreliable and inaccurate. Bright spot amplitude anomalies are purely an elastic effect. Only the right combination of petroleum fluid content and rock physics properties (such as porosity and lithology) can result in bright spot amplitude response. Thus, the bright spots do not always represent the presence of petroleum fluid, and non-bright spots do not always mean the absence of petroleum fluid (Young, 2006).