bluuebunny/crossref_metadata_2025 huggingface dataset:
Reservoir Characterization from Gas Ratio Analysis Using New High Efficiency Gas Extraction System
Authors: Zhou Leifeng , Blue D. Duncan
Published: March 2015

Mud logging gas detection and chromatography have been traditionally used as indicators of hydrocarbon occurrence and wellsite safety. However, the application of mud logging gas as a reliable reservoir characterization tool had previously been hindered by its semi-quantitative nature, noticeably the inability to get repeatable responses in all environments so that the analysis can be used as a trusted analytical tool, regardless of gas trap operating conditions and surface environments.

A new gas extraction system, Constant Volume Gas Trap (CVGTTM), is now available at wellsite and has been successfully run worldwide. Equipped with several innovative features, CVGT not only improves mud gas extraction efficiency, but also reduces the effects of environmental and operation conditions on quantitative gas measurement. Coupled with high accuracy and a fast cycle gas chromatography system, CVGT gas ratio analysis provides a cost-effective approach to evaluate reservoir fluid types, contacts, and other critical information needed for subsequent fluid sampling, testing, and development programs.

Several applications of gas ratio analysis are presented that complement other reservoir characterization tools and approaches. Vigorous data QC are enforced to reduce the effects of any non-reservoir fluid contributions. Most suitable ratio cutoffs are determined for the target reservoirs. These cutoffs are determined through a variety of factors, in particular the known reservoir fluid properties from offset wells in the area. C1/sum(C1~C5), and the combined use of gas wetness ratio (GWR) and light heavy ratio (LHR) have proved to be the most valuable out of all the gas ratios investigated. Together with total gas and gas chromatography, these ratios and ratio combinations are able to indicate the occurrence of reservoir zone, the types of fluid in it, and the fluid contacts. Fluid types defined from ratio analysis are correlated with LWD/wireline data, particularly the resistivity, cross-over of neutron and density, and pressure gradient analysis. This ultimately leads to better reservoir characterizations with regards to its vertical connectivity, compartment and caprock efficiency, etc.

INTRODUCTION

Accurate reservoir characterization in terms of accurate fluid type, contacts, and vertical evolution and compartmentalization at the early stage of well construction is vital for guiding subsequent fluid sampling, completion, well testing, and production planning and designing. It is also critical to identify the rock and fluid properties accurately in real time to maintain the well in an optimal trajectory for maximum productivity. Such endeavors are often not trivial, especially in producing reservoirs where complications arise due to altered gas/oil/water contacts from virgin status. Such alterations of contacts often result from combined effects of gas cap expansion, continuing production, and water injection.
Optimization Method for Line Pipe Selection & Sizing (A case study from Saudi ARAMCO water injection system)
Authors: Al-Mahamidh Hadi Salim , Al-Khalifa Mohammed Hussain , Dajani Hatem A.
Published: March 2015

This paper intends to address the proper method for carbon steel pipe-sizing using Barlow's Formula as the initial step in pipe-sizing mechanism; and how this formula will assist us to select the proper grade of line pipes. The paper proposes that the grade of the carbon steel line pipe has to be determined first, and the sizing of the carbon steel line pipe has to be determined second. The proposed method for selecting the proper grade of line pipes comes from personal experience with surface water injection in Saudi Arabia.

Introduction

Pipelines are major facilities in oil industry; most are metal types of carbon steel. Millions of US Dollars have been spent on funding projects of carbon steel pipelines. In light of changes of world economy where prices of carbon steel line pipes have increased dramatically, either due changes in cost of energy used for manufacturing the line-pipes, or else. As engineers, we have to re-examine requirements and specifications in order to change them to meet the essential requirements and continue using carbon steel line pipes at fair cost. This can be achieved once the proper grades of line pipes are being selected without over sizing in the requirements.

Material Strength

The strength of any metal material is determined by the tension test, which measures the tension force and the deformation of the test specimen. The stress which gives a permanent deformation is the yield strength. The stress which gives rupture is the ultimate strength. Figure-1 shows the common stress-strain curve. Figure-2 shows the yield strength and the ultimate strength of the most common line pipes used in the industry.

Discussion

The Barlow's formula is not totally new for uses in pipe-sizing. It has been used in every day applications for determining pressure rating of pipes. Also, it has been used with other fluid equations in hydraulic and simulation applications. However, with software available today for hydraulic simulation, we tend to overlook such simple formula and rely on the hydraulic software to perform the sizing calculations, ignoring the selections of the line pipes grades, and the differences between these grades of line pipes. Fortunatly, any grade is often made in all sizes, and that is why we do not pay much attention to the type of grade that would be used in a project as long as we can get the pressure rate and the size we need. Therefore, it is advisable that line pipe grade be selected based on the pressure rating of the system at first; then the hydraulic simulations or other fluid measurements can be utilized for determining: the proper size or any further sizing, fluid velocity, delta pressure, or other fluid parameters that have to be evaluated.
The Influence of Geological Heterogeneities on Well Productivity: Simulated Outcrop Analogue
Authors: Al-Oreibi Lama Abdul Nasser , Reijnders Gert-jan C.A. , Jennings James W. , Carter Sam , Poppelreiter Michael , Zampetti Valentina , Dawans Jean-Michel Laurent
Published: March 2015

Introduction

What level of geological detail is required to give a meaningful representation of a reservoir model? Is it worthwhile to spend the time, money and effort to assemble a high-resolution geological model or will simpler models suffice? How coarse can a model be to provide the fastest possible execution while simultaneously preserving enough geological detail for realistic performance predictions?

To answer the holistic question of how much resolution needs to be preserved, a high resolution geological model of an outcrop of the Khuff formation (Oman) is used to develop a methodology to assess the impact of the preservation of geological heterogeneities. Sensitivity tests to various grid sizes have been carried out to determine what level of detail needs to be retained to achieve representative well production forecasts.
3D Seismic Attributes, A tool for well Placment in Complex Reef Build-up
Authors: Najia Walid , Bellah Samir , Al Shehhi Jamila
Published: March 2015

This middle cretaceous reef build up reservoir has similar problems to other fields of similar setting in the region, regarding upper contact in the form of Karstification with a mixture of fill, shally interbedding, lateral / vertical tight intervals, uneven Vug distribution and large transion zone.

Those have presented a great challenge to adequately place horizontal wells, where near surface well path will intercept the Karst topography extending in the reservoir with its potential drilling hazard while away from the surface wells will end up in high SW zone. In this context, well placement becomes a real challenge. Few wells had to be plugged and side tracked adding several million dollars to the drilling cost beside the lost in hole equipment.

After our 3D OBC seismic survey, the team attempted and succeeded in using (for the first time) a group of seismic guided Reservoir characteristic attributes to identify a sweet spot (in our case a sweet level) and develop a well path plan that properly placed the well trajectory deep enough away from Karst and surface irregularity avoiding the danger of drilling hazard and penetrating the upper layer, yet shallow enough not to fall within the high water zone.

Our success story is supported by wire line image log and acoustic logs and keeping the well cost at reasonably estimated values.

The paper reviews difficulty normally faced in drilling those wells, summarize original work carried out in selecting seismic guided attributes (as part of the reservoir characterization) to build a well design based on those findings. The paper will finally present a successful drilling case of 2700 ft supported by wireline logs.

Introduction:

The field is located in offshore Abu Dhabi and has been producing for the last 25 years. It covers about 400 Km2. The producing reservoir consists of series of middle cretaceous culminations covering almost the entire field. It is a reefal and shoal limestone build-up characterized by a typical thick bottom water drive reservoir. The dry oil interval is relatively thin and sited above huge transition zone.

Since the field discovery, over 60 vertical, deviated and horizontal wells were drilled in the field as oil producers and water injectors. Many other wells were side tracked to be horizontalized for maximum reservoir exposure.
SIMOPS During Construction, Commissioning, Startup, and Operation of the World's Largest LNG Project
Authors: Schmidt Kevin
Published: March 2015

This paper will highlight the best practices and lessons learned from Qatar Liquefied Gas Company Limited (2)'s (QG2) development and implementation of an onshore Simultaneous Operations (SIMOPS) procedure and organization. It will show the unique steps taken during the construction, commissioning, start-up and operation of the world's largest Liquefied Natural Gas (LNG) process train. These steps ensure minimal impact of simultaneous activities in construction and operation of a live plant.

The complexity of the situation demanded Management commitment, effective communication and a systematic approach including defined procedures and detailed planning while working with independent organizations. This paper will emphasize the importance of well organized and continually monitored SIMOPS programs to the safe and successful implementation of large scale projects with staged turnovers. The programs can also be applied to situations in which there are multiple construction projects in a single area to address interfaces during construction through to start up.

Focus will be on three main areas:The development of a Matrix of Permissible Operations (MOPO) that clearly laid out what activities were allowed to happen simultaneously in the same area or on the same system.The use of a standard Permit To Work (PTW) system facilitated by SIMOPS area plot plans, updated weekly. This allowed for a single transition when switching from the construction PTW system and allowed the operators and the Contractor to become familiar with an Operations PTW as they were both involved with work inside the operating plant. The SIMOPS area plot plans are updated with input from all organizations involved. This input makes it clear who controls specific permits in each area minimizing delays and incidents caused by mismanaged PTW interfaces.The building of an onshore SIMOPS Plan fostering an operations organization dedicated to SIMOPS controls and continuous improvement. This overall plan that lays out the keys to SIMOPS area definitions and the requirements in these areas such as PTW and organizational responsibility was the foundation of QG2's program. Developing the SIMOPS Plan early on facilitated a staged turnover plan for Process Train 4.
Successful Field Application of an Inhibitor Concentration Detection System in Optimising the Kinetic Hydrate Inhibitor (KHI) Injection Rates and Reducing the Risks Associated with Hydrate Blockage
Authors: Lavallie Orlin , AL Ansari Ahmed , O'Neill Stephen , Chazelas Olivier , Glenat Philippe , Tohidi Bahman
Published: March 2015

Currently, hydrate inhibitors are injected at the pipelines upstream based on the calculated/measured hydrate phase boundary, water cut, worst pressure and temperature conditions, and the amount of inhibitor lost to non-aqueous phases. In general, no means of controlling and monitoring are available along the pipeline and/or downstream to assess the degree of inhibition. Often high safety margins are considered to accommodate for the uncertainties in the above parameters and to ensure gas hydrate risks are eliminated. However, despite these efforts hydrates do still form and this can result in considerable economical and safety concerns.

As a result of a joint industry project, a novel device based on electrical conductivity and sonic velocity (C-V technique) has been developed for monitoring the hydrate safety margin to optimise inhibitor injection rates. The system determines the amount of inhibitors (e.g., salt, KHI, methanol, MEG, etc…) in the aqueous phase and the degree of inhibition they can provide.

The device has been successfully applied in determining the amount of KHI in produced water from the Dolphin field in Qatar. Compared to conventional chemical techniques the device is much faster (less than 3 minutes) and less labour intensive and there is no chemical requirement.

In this presentation, the results of the trial of this device in determining KHI concentration in produced water are described. The results shows that this new technique is very fast and reliable, optimising the KHI injection rate, improving the economy and reliability of hydrate inhibition strategy, and minimising the impact on the environment.

Introduction

From a flow assurance point of view, gas hydrate formation is undoubtedly dreaded as the major risk of plugging the oil and gas production systems.

Natural gas hydrates.

Natural Gas hydrates are ice-like crystalline compounds that form whenever water molecules contact hydrocarbon gas molecules of low molecular weight (from methane to butane) or other gas molecules such as N2, CO2 or H2S. The hydrate crystals can be represented as a network of hydrogen-bonded water molecules forming cages with gas constituents trapped within. Conditions promoting gas hydrate formation are high pressure (typically > 30 bar) and low temperature (typically < 20°C). Precise conditions in terms of pressure and temperature depend on the composition of the fluids. Hydrate formation can occur for all the produced fluids if required P & T conditions are reached: natural gas, gas with condensate and crude oil with associated gas, with condensed or formation water.
Deep Fluid Diversion for Profile Control and Oil Displacement Technologies
Authors: Liu He , Hanbing Xu
Published: March 2015

Through 50 years of water injection production, Daqing Oilfield has developed matched chemical and mechanical zonal injection and production technologies. However, due to residue oil scattering here and there, and serious low effective and non-effective circulations happening in high watercut period, the existing profile modification system can hardly meet reservoir requirements. Currently, water injection well averagely serves 3 to 4 intervals, and oil wells mostly produce commingled. It's urgent to realize multi-zone fine zonal water injection, oil well fine production and injection-production well integrity. In later high watercut stage, to enhance water flooding recovery rate is our new challenge. Based on profile control technology, we've developed low cost, long efficiency deep fluid conversion profile control and oil displacement technologies, and high efficiency fine control water injection technologies, which contribute to the accuracy of water injection, and recovery rate rise of 2–3% in reservoirs with watercut above 90%.

Introduction

Most fields in Daqing Oilfield are continentally sedimented with high heterogeneity. With decades of water injection development, the heterogeneity is worsened, and large pores are developed in deep reservoir and near wellbore formations. Along the large pores is the water flow strengthened, and less or no water passes through low permeability zones. What is worse, in deep reservoir formations, the large pores and high permeability zones are enlarged, even water channels are formed, proved by core analysis. As a result, the deep reservoir heterogeneity is getting worse. More and more water passes through the high permeability zones, while the low permeability zones are weakly flooded by water and little oil is moved. High water production from the high permeability zones affects well productivity a lot, as it usually leads to high bottom-hole pressure, which inhibits oil being produced from low permeability zones. Since the high permeability zones have already been flooded largely, the injected water takes little or no effect on moving the remaining oil.

To solve the problem, conformance improvement technique gets in our mind. However, near wellbore profile correction treatment can only improve the heterogeneity in the vicinity of the injector. For high heterogeneity in deep reservoir areas, the technique needs improving. A type of high strength swelling delayed particle and a type of zwitterionic polymer gel are developed in the work and used in the field.
Effects of syn-depositional tectonics on platform geometry and reservoir characters in Miocene carbonate platforms of Central Luconia, Sarawak
Authors: Ting King King , Pierson Bernard J. , Al-Jaadi Omar , Hague Paul F.
Published: March 2015

It is commonly assumed that the Miocene carbonate platforms of Central Luconia, Sarawak developed and grew on a stable substratum. This paper documents evidence of syn-depositional tectonic movements in the 'Mega Platform' in the northern part of the Central Luconia Basin. Detailed 3D seismic interpretation techniques consisting of spectral decomposition, acoustic impedance opacity rendering, and structurally oriented semblance filtering were used to better constrain geological processes affecting, controlling and modifying the evolution and demise of the platform. Syn-depsositional tectonic movements impacting stratigraphy architecture at a scale sufficient to fragment or break up a platform occurred during platform growth. Depending on the magnitude of the movements, carbonate platforms responded in different ways:Platform fragmentation and permanent separation of part of the platform; this happened in the southern part of the mega-platform early on in its growth history. Two smaller platforms separated from the main one and continued growing as separate entities.Step subsidence and infill of new accommodation space; part of a platform subsides but the surviving part generates sufficient sediment volume to fill in the new accommodation space through progradation. A flat platform is eventually restored over the whole or part of the initial platform surface.Step subsidence and contraction of a platform; part of a platform subsides but the surviving platform does not have the capacity to produce the sediment volume required to fill in the new accommodation space. The down-stepped part of the platform eventually drowns.

Faulting not only created topography as a template for the initiation of carbonate platform deposition but also as pedestals for the localization of backstepped platforms. Cessation of syn-depositional faulting may create tectonic quiescence period that instigated progradation as a result of deceleration of accommodation-space production.
Improving SAGD Performance Combining with CSS
Authors: Ghanbari Ebrahim , Mighani Saied , Shaabani Emadoddin , Alipour Reza
Published: March 2015

There are large resources of heavy oil reservoir with high viscosity that cannot be produced by natural depletion. The main obstacle to produce from these large deposits of heavy oil and bitumen resources is the high viscosity of these oils. This large amount of oil can be produced considerably by thermal EOR (Enhanced Oil Recovery) methods. The Steam Assisted Gravity Drainage (SAGD) and Cyclic Steam Stimulation (CSS) process has been found as a promising EOR process to recover bitumen and heavy oils.

In this paper, the SAGD and CSS process were combined together to benefit advantages of both methods. When the wells are shut-in to soak, injectivity of steam during SAGD process will increase. So the chamber can extend more easily to drain the oil toward production wells. During this study, possibility and efficiency of this new method was assessed by simulation study using CMG STARS and sensitivity analysis was conducted to optimize the process. The production performance of this method is compared to conventional SAGD and CSS process.

Simulation results show that with the same steam injection rate, this new method has more oil recovery than conventional SAGD, due to better development of steam chamber into reservoir. Also as a result of lower steam-oil-ratio the production cost is reduced.

Introduction

Steam Assisted Gravity Drainage (SAGD) and Cyclic Steam Stimulation (CSS) processes have been found as two efficient methods for heavy oil recovery. The Steam Assisted Gravity Drainage (SAGD) using gravity as driving force and a pair of horizontal wells for injection/production ensures both a stable displacement of steam and economical oil production rate [1]. As shown in figure 1, SAGD requires two wellbores. One wellbore continuously injects steam and a second one continuously produces mobilized bitumen and condensed steam. Horizontal wells are used to enhance reservoir access and thus well productivity [2].
Effective Permeability 3D Model Unlock the Uncertainty Production in Low Perm Fluvial-deltaic Reservoirs, Nilam Field, Kutai Basin, Indonesia
Authors: Corbellini Jose Benito , Harnondo Ratno Adi , Negara I. Made Agus Sutha , Gultom Luhut Partumpuan , Hazman _ , Soenoro Amireno , Benyamin Benyamin
Published: March 2015

Nilam Field is located in Kutai Basin, East Kalimantan, Indonesia, which even more than 40 years of exploitation, these fluvial deltaic reservoirs, of age Early-Middle Miocene, still have significant reserves of gas, that occur in poor quality reservoir rocks in structural, stratigraphic or combination traps, that were not entirely examined. This case history describes some works carried out in this field over these low permeability reservoirs, locally known as G's sandstones, in order to understand the root of the erratic production results, evaluate the formation damage, identify the potential areas and present the right solution for recovering the undeveloped accumulations.

Seventeen cores were taken in these horizons, with the main purpose to obtain the necessary information for determination and characterization of rocks and the explanation of trapped phase. An understanding of multiphase properties as capillary pressure, water-gas relative permeability, fluid compatibility and the right model for effective permeability, calibrated by nodal analysis techniques, are mandatory to properly define the input for the 3D petrophysical models. In the past, the failure to fully understand these concepts, especially the effective permeability model and its relationship with the critical water saturation, less than 40% for these reservoirs, has led to a not clear understanding the controls on gas-field distribution. Therefore, effective permeability to gas as function of varying water saturation is the key factor to understand the reservoir productivity.

The integration of critical petrophysical aspects with geology using geostatistical methods had produced comprehensive overlay models that were used to delineate the best areas for developing the significant amounts of un-recovered reserves with minimum uncertainty in production. The use of this methodology has arrived not only to achieve this target but also has shown an incremental gas production as much as 10 times, in some areas of the field, during the last 2 years.

For this study, two sources of information were available: Core data and Log data. Both were analyzed to get reliable information to characterize the G Reservoirs.

Introduction

This history case, of erratic production forecast, describes some work carried out in a low perm fluvial-deltaic sandstones of age Early-Middle Miocene in Nilam Field.

Nilam Field that is located in Kutai Basin, east of Kalimantan, Indonesia, Fig. 1, was discovered in 1968, but after 43 years of production much of the reservoir remains to be understood.

These rocks, that exhibit normal reservoir quality but, in particular areas, poor gas production, were studied with the purpose to explain the disappointing gas rate results and assess the remaining considerable reserves, mainly in the eastern flank of the Nilam structure.
Utilizing GHV Management in Field Development Planning
Authors: Wiboonkij-arphakul Chaiyaporn , Tsai IngJye , Jablonowski Christopher J.
Published: March 2015

This paper discusses the challenges of integrating into an existing gas field a marginal field with poor gas quality that would otherwise be left stranded.

To prepare for the poor quality gas, this study added gross heating value (GHV) to the traditional scheduling analysis to ensure that the quality of sales gas blended from various fields would always meet specifications. The addition of GHV to the traditional scheduling analysis required devising a GHV forecasting method, creating a GHV management procedure, and implementing a new revenue allocation method. Each of these innovations required specific tasks. Examples of these tasks and their challenges are presented in this paper.
Evolution of Geosteering Technology Helped in Successive Development of a Brown Field - Case Study from Mumbai High
Authors: Anand S.K. , Kumbhar Jogeswar , Singh Uday , Jeelani Mohammad Sazid H.M. , Majumdar Chandan , Singh Juli
Published: March 2015

Mumbai High, a highly heterogeneous multi-layered carbonate sequence with shale intercalation, played a critical role to quench the energy thirst of a big developing country like India. Mumbai High field is divided into two blocks i.e., Mumbai High North (MHN) and Mumbai High South (MHS) by a major WNW-ESE trending graben containing impermeable shale. After 34 years of production, the field is in its brown stage and radical decline in production has been observed. Horizontal drain holes were introduced to counter this problem by increasing the reservoir exposure. However the biggest challenge faced so far is the placement of the horizontal drain hole within 2 - 4m thick layer with significant structural variations. Exit into shale due to presence of sub-seismic fault and minor dip change is a common observation while drilling.

Geosteering technique has developed as the industry has shifted its focus on horizontal well drilling. Initially wells were placed using log correlation, through understanding of the reservoir which often helped to drill a better horizontal well. The simple log-correlation technique was improved with the introduction of azimuthal measurements. However the approach was still reactive and a need was felt to have a proactive approach. Present sophistication has met the requirement by providing early indication of the approaching boundary.

This paper will illustrate various techniques for successful placement of drain holes in such complex reservoir. Also, it will capture the chronological evaluation of Geosteering technology and how they are used to develop this field. The drilled wells in all the cases have proven to be the successful drain holes and prolific producers compared to the surrounding wells.

Introduction

Mumbai Offshore Basin, a pericratonic rift basin in the western continental shelf of India, covers about 148,000 km2 from coast to 200 m isobaths and the sedimentary fill ranges from 1100–5000 m (Fig.-1). Several large oil and gas fields have been discovered in this Basin, and the presence of hydrocarbons has been established in the multiple pay zones belonging to L-III limestone reservoir of Miocene age in Mumbai high. The L-III limestone reservoir is a multi-layered reservoir and has been divided conventionally from top to bottom into major layers A, B, C, D, E, and F separated by intervening shale and argillaceous tight limestone. 'A' layer is further subdivided into Al, A2-I, A2-II, A2-III, A2-IV, A2-V, A2-VI and A2-VII and along with layers B, C constitutes the main producing horizon (Fig.-2).
Well Productivity Prediction for Laminated Reservoirs Using Borehole Electrical Image Logs.
Authors: Chokthanyawat Suchart , Daungkaew Saifon , Athichanagorn Suwat
Published: March 2015

Due to increasing costs in hydrocarbon exploration, formation evaluation needs to be efficient in order to avoid excessive expenditures. Proper reservoir characterization in thinly laminated reservoirs is a key to successful field development. These thinly laminated reservoirs are complex due to their vertical heterogeneity. As a result, there is low resistivity contrast between water and hydrocarbon bearing zones when standard resistivity logs are used. Thus, it is crucial to deploy a high resolution formation evaluation in order to capture reservoir pay and detect hydrocarbon zones.

This paper aims to demonstrate a methodology of using borehole electrical image log to determine effective permeability. The paper is the first attempt to develop a numerical technique to build a correlation between synthetic resistivity derived from borehole electrical image tool with other dynamic permeability measurements such as dual packer formation tester. A single well predictive model was used in the process to generate a high resolution numerical radial model from high resolution log data.

Since the 1980's, micro electrical imaging tools have mainly been used for sedimentological and structural interpretation, qualitative interpretation for sand quality, and also for the sand count. However, from the systematic integration of borehole electrical image, NMR, pressure transient from an Interval Pressure Transient Test (IPTT) in the thinly bedded reservoirs, it is possible to use electrical image log variations for permeability estimations. This study therefore aims to develop the methodology for actual field data to predict well productivity.

Introduction

Laminated formations pose two major evaluation challenges for reservoir engineers:-

1st is the classic low resistivity pay problem as seen in vertical wells. Layers of clay, silt and fine-grained sand distributed within a hydrocarbon bearing sand will significantly reduce the apparent resistivity measurement. This low resistivity results in wrong fluid identification and therefore this zone might be overlooked.

2nd is the high angle well evaluation problem. The same laminated formation, when measured by an induction tool at moderate - high relative dip, will exhibit an increase in apparent resistivity beyond that measured in the vertical well.

Again, the inaccurate calculation of water saturation and hydrocarbon volume may cause the error in reservoir estimation.
Geophysical Reservoir Characterization and Modeling of Marrat Carbonate Reservoir in Minagish Field, West Kuwait
Authors: Jalil Abdul Aziz , Verma Naveen Kumar , Al-Mutairi Khaled M. , Al-Khamees Waleed Khamis , Rahaman Mafizar , Laiq Kamran , Ahmed Mukarram , Sabry Ahmed
Published: March 2015

As a part of an integrated field development study, comprehensive seismic interpretation, velocity modeling and inversion were carried out for the Minagish Marrat reservoir. The geophysical lithology-porosity effects were imaged and quantified for the first time, and used for detailed reservoir characterization and 3D geological modeling.

Recently acquired 3D PSTM seismic data was used to interpret and refine the key horizons over the Minagish field. The multi-attribute analysis was used to quality control the horizon picking and to interpret the faults accurately, particularly since the data was contaminated with multiples. Advanced post-stack attribute analysis provided insights into the faults, fractures and matrix properties of the heterogeneous carbonate sequences to understand the reservoir architecture at all scales.

Several velocity modeling scenarios with combination of wells and seismic velocity were evaluated to investigate the structural uncertainty for accurate depth conversion. A total of 57 key wells were used to build a robust velocity model from surface to 13,000 ft with an average accuracy of + 10 ft at the reservoir level.

3D PSTM seismic volume was used for post-stack acoustic impedance inversion to map the reservoir properties from seismic. The objective of one of the key rock physics analysis was to understand the mineral-elastic response of the reservoir rocks. Advanced well log data conditioning with rigorous quality control was performed on 22 wells used in the inversion process. Fully integrated core and well log derived mineralogy results were used to prepare sonic-density scatter plots to understand and calibrate the response in terms of mineralogy (e.g. clay, dolomite, and calcite) as well as lithofacies with varying porosity. This meticulous calibration resulted in good relative and absolute acoustic impedance transforms to derive porosity, which in-turn was used for modeling the reservoir properties in 3D geological model. This model has provided a strong base for horizontal and multilateral well placement as the results from recently drilled first horizontal well has shown excellent match with the model predicted reservoir structure, lithofacies and porosity.
Recent Step-out Exploration in the Greater Sirikit East Area, Sirikit Oil field, Onshore Thailand, a Model for Overlooked Area
Authors: Saifuddin Farid , Phaungphuak Sunantha , Matha Sureena , Ratawessanun Watanapong , Nuada I. Nengah
Published: March 2015

Greater Sirikit East (GSE) Field represents recent step-out exploration success in the east of Sirikit Main Field. Sirikit Main was discovered in 1981 and remains the largest field in the basin, with surrounding smaller fields: Sirikit West (northwest, 1983), Thap Raet (north, 1988), Sirikit East (northeast, 1992) and Nong Jig (southwest, 1999).

GSE comprises of multiple blocks defined by structural and stratigraphic closures. It shares common reservoir and source rock with Sirikit Main. Some of the trap types and seals are also common. However, some trap types and seal elements are not typical in Sirikit Main. More detailed subsurface evaluations were conducted to explore all the working petroleum systems.

This is the key and challenge to the GSE that had been overlooked in the past due to the absence of considerable structural closure in the key horizon maps.

Aggressive step-out exploration in GSE started in 2006. More than 12 exploration/delineation wells have been drilled to date testing multiple blocks and plays. The exploration concepts have been continuously developed by taking the feedback from the well post drill evaluation. The new developed or refined concepts were then applied to the subsequent exploration/delineation drilling. This cycle allows better risk mitigation as well as more accurate well targeting.

To minimize exploration cost, time and risk, following strategies have been adopted whenever feasible: To use existing drilling surface location, to combine multiple targets and to provide back-up side-track target. Utilizing existing surface location made significant time and cost saving by avoiding costly land acquisition, access road building and time-consuming environmental impact assessment.

Continuous exploration and delineation drilling in 5 years has changed the GSE area. The previously overlooked large area that looks like a monocline in main marker maps turned out to hold multiple hydrocarbon accumulations involving both stratigraphic and structural traps.

Introduction

Greater Sirikit East Field is located just to the east of the Sirikit Field in the S1 concession, Phitsanulok Basin (Figure 1), Central Plain Onshore Thailand, approximately 400 kilometers north of Bangkok. The concession is 100% owned and operated by PTT Exploration and Production.

Sirikit Field was discovered in 1981 and remains the largest field in the basin. Up to 2000, 5 adjacent smaller fields have been discovered. Sirikit West Field in the northwest was discovered in 1983. Thap Raet Field in the north, discovered in 1988, Sirikit East in the Northeast, discovered in 1992, Nong Jig oil in the southwest, discovered in 1999, and Nong Pluang gas in the south-southwest, discovered in 2000. The first-discovered Sirikit Field is normally called as Sirikit Main Field in order to distinguish it from the neighboring fields bearing 'Sirikit' name.
Use of Nano-Metal Particles as Catalyst Under Electromagnetic Heating for Viscosity Reduction of Heavy Oil
Authors: Greff John , Babadagli Tayfun
Published: March 2015

In order for heavy oil and bitumen recovery to be efficient, all components present within the oil must be produced. To achieve a highly efficient production process is it essential that we are able to produce asphaltenic components and limit their precipitation. Solvent and conventional thermal techniques are largely limited in their ability to crack asphaltenic components. Thus, new technologies and catalysts are needed to be more efficiently recover heavy oil.

When nano-sized metal particles are present, they catalyze the breaking of carbon-sulfur bonds with in asphaltenic components. The result of this process is an increase in saturates and aromatics, while simultaneously reducing the aphaltene content. This process dramatically lowers the viscosity of heavy oil and bitumen by significantly reducing the average molecular weight. This effect can be dramatically increased by having a strong hydrogen donor present, and can be completely inhibited by the removal of all hydrogen donors. When conducting these types of reactions in-situ, it is very difficult and expensive to introduce strong hydrogen donors. Therefore, it is imperative that hydrogen donors be created within the oil rather than be introduced from an external source.

In this paper, we investigated the effects of microwave radiation, using a s 2.45 GHz emitter, on the recovery of heavy oil from a sand pack. Experiments were conducted with and without nano-sized nickle catalyst being present. Heavy oil samples were heated at different power levels until recovery of heavy oil leveled out. In all cases, the nano-nickle catalysts performed better than their microwave oil counterparts. This is due to the increased cracking and vaporization which was demonstrated by Greff and Babadagli (2011) to take place in the presence of nano-size metal catalyst and microwaves.
4D Seismic Integration with Production Analysis for Pressure-Saturation Detection
Authors: Mad Sahad Salbiah , Basaharudin Shuhadah , Abdul Halim Mohd Firdaus
Published: March 2015

Introduction

4D seismic (or seismic reservoir monitoring) have been applied to many fields in the world, to monitor reservoir changes due to production. Monitoring reservoirs based on changes on seismic response due to fluid substitution and/or changes of pressure are able to locate bypassed oil, water/gas-flood fronts or steam-fronts.

Objectives and Methodology

The primary objectives of this study are integrating the 4D production data with seismic difference maps and determine the changes occurred in the reservoir because of hydrocarbon production or by the injection of water/ gas into the reservoir by comparing the repeated production datasets. Suitable methodology using PETRONAS In-House software were developed to search for the best results in three individual analysis; (i) interpretation using Production History (all region), (ii) integration of tracer database with seismic attribute maps (south west region) and (iii) integration of Saturation Data with 4D Quadrature Amplitude Difference Map (all region).

Geological Background

The reservoir in Z field represents mid-slope turbidites consisting series of fining upwards sequences, contain basal conglomerates and channel sands associated with levee and overbank sediments. The oil and gas in the field trapped in Early to Mid-Miocene reservoir sands above a faulted dome caused by underlying salt intrusion. The reservoir sub-divided into two mainpackages based on Calcareous Nanoplankton (CN) age dating.
Effect of Heat Treatment on Mechanical Properties of Expansion Cone Material
Authors: Qamar Zahid Sayyad , Pervez Tasneem
Published: March 2015

AISI D6 is a high-carbon high-chromium cold-work tool steel. It has excellent resistance to wear and abrasion, high compressive strength, and good edge holding quality and dimensional stability. These properties make it an ideal choice for use as a tool for blanking, punching, cropping, shearing, trimming and clipping. One of its most promising and important applications is in the form of conical mandrel for expansion of steel tubulars used in oil and gas exploration. Solid Expandable Tubular (SET) technology is being successfully employed for various downhole applications such as slimming of oil and gas wells, and isolation of water-producing zones. The mandrel, made from a special material (generally D6 steel), is hydraulically pushed (or mechanically pulled) through a steel tubular. This cold work expands the tubular beyond its elastic region, causing permanent deformation. To withstand the high level of repeated thermo-mechanical stresses, cone material must have certain specific properties. The work reported in this paper covers heat treatment and mechanical testing of tensile and impact specimens of D6 tool steel. The heat treatment process consists of annealing, hardening/austenitizing, air or oil quenching, and single or double tempering. Mechanical testing includes hardness, tensile properties (elastic modulus, yield strength, ultimate strength, and ductility), and impact strength. Analysis of the test results leads to the identification of an optimal heat treatment sequence for D6 steel that would yield the best combination of desired properties for the expansion mandrel. Optimum material properties would ensure dimensional accuracy of the expanded tubulars and a longer mandrel life.
Use of Reservoir Simulation to Help Gas Shale Reserves Estimation
Authors: Segatto Michele , Colombo Ivan
Published: March 2015

Scope of this paper it to supply a workflow for gas shale simulation: starting from selection of best porosity model, through a definition of the most impacting phenomena hierarchy, it comes to a real application on gas shale in Barnett basin.

Gas shale exploitation consists mainly in massive drilling campaign: this strategy can be successfully implemented where the costs per well is low, but elsewhere an accurate investigation including numerical modeling of gas shale reservoirs could be essential especially for defining optimal well spacing.

We test several implementations of multi-porosity models (dual porosity, multi porosity, dual permeability). Even if all the models can simulate properly gas shale production we use "single porosity-like" that couples the advantage of dual permeability and single porosity models.

Tests on synthetic cases have shown that gas production from shales is meanly affected by fracture spacing, proppant distribution inside induced and natural fractures, desorbed gas and in situ stress change.

A real case of shale gas exploitation in Barnett shale is successfully matched by single porosity-like model, with SRV extension from microseismic mapping, 'water saturated' and pressurized hydraulic fracture, adsorption and change of in situ stress. Match of the water flow-back is obtained with non-equilibrium initialization: setting fracture cells with higher pressure and water saturation than surrounding ones. The matched case is then used as starting point for further analyses and sensitivities.

Final goal is to provide a workflow for frontier basin where few production data are available with respect to what happens in USA and to calibrate decline curve for reserve estimation.

Introduction

Referring to gas shale means in 90% of cases talking about Barnett Basin (Texas, USA). They symbolize the ideal play with huge number of wells already producing and where the market condition gives the opportunity to massively apply available technology and to test new development strategies. Anyway uncertainties still remains. Decline curves analysis are largely used to assess reserves and future development plans, but reservoir simulation can give an added value adding more physics or controls compared to Decline Curves.

As known, 3D simulation of gas shales is not a simple task because of complexity of storage and transport system, long water flow-back period, uncertain proppant distribution, gas desorption, etc..
RasGas Rigless Drift Experience: New Technology and Evolving Best Practice - North Field, Qatar
Authors: Van Nuis Russell Robert , Mercer Larry , Morrow Timothy Ian
Published: March 2015

RasGas Company Limited (RasGas) operates a continuous and comprehensive Rigless well surveillance and monitoring program in the North Field, State of Qatar. The wellbores are designed to produce at high rates, therefore each well is a substantial asset and every intervention operation is critical to maintaining production capacity.

A drift operation is usually performed in each well to ensure logging objectives can be met safely. The normally unmanned offshore wellhead platforms (Fig. 1A) have limited deck space (Fig. 1B) which prevents simultaneous slickline and electric line operations.

Starting in 2007, RasGas deployed drifts on electric line, under certain conditions, using a 4.5-in. OD hollow carrier dummy perforating gun to ensure contingency fishing capability with a 4-in. OD overshot. Although this approach was favorable from a logistics, cost and schedule standpoint, the tool held-up in the perforations in three wells highlighting the risk of a lost tool and/or uncontrolled wire recovery, under high pressure sour conditions, due to a cable head weak point release.

Additionally, the surveillance program was delayed due to incremental drifting campaigns using mechanical wireline.

The paper will present RasGas drift experience and technical study results on the formation of perforation burrs and scale. Remediation of these obstructions should be a one-time event based on a study which indicates scale deposition is only expected to occur within the first few months of production. Additional discussion will include the development of two innovative slickline tools (De-burring Tool and Smart-Drift Tool) with significant advantages over conventional fixed diameter broaching/drift tools including a release mechanism to pull free from a stuck position.

The resulting optimized drift policy is based on an initial drift with a 5.75 in. OD Bell guide on mechanical wireline to ensure a successful latch of a 1-11/16-in. fishing neck. If wellbore remediation is required due to restrictions, the appropriate tools are selected based on the lessons learned described within the paper. After full wellbore access is established, future drifts can be performed safely on electric line using the new technology Smart Drift Tool to optimize logistics, cost and project schedule. The paper applies to other operators conducting cased hole logging programs and/or removing downhole perforation burrs or formation scale to meet well intervention objectives.