bluuebunny/crossref_metadata_2025 huggingface dataset:
What We Learned from a Study of Re-fracturing in Barnett Shale: An Investigation of Completion/Fracturing, and Production of Re-fractured Wells
Authors: Wang Sharon Yunhong , Luo Xin Lucy , Hurt Robert Samuel
Published: May 2016

The success of the Barnett shale helped to revitalize the oil and gas industry in the United States, and sparked a wave of shale development programs. At the same time, it has caused practitioners to rethink how, or even if, we can apply certain theories and technologies developed and implemented in conventional reservoirs to unconventional reservoirs. One fundamental difference in unconventional reservoirs is several orders of magnitude lower rock matrix permeability, largely requiring stimulation for economic development.

Re-completion/fracturing in shale reservoirs is a means to increase production by accessing reserves beyond the volume achieved from initial completions. Re-fracturing may also be applied to wells with inefficient initial completions, less-than-optimum designs or executions, and in depleted wells in which it is possible to treat previously un-stimulated rock volume.

We performed this study to discover how production is impacted by recompletion and re-fracturing. By studying specific treatment and production data sets in the Barnett, we searched for new insights about how shale plays should be developed. In this work, we extracted about 200 re-fractured or re-completed wells with treatment information and production data in the Barnett Shale play from a service company's database and a public well database. In this analysis, we took into account treatment data in both initial and refracturing, and evaluated their impact on long-term recovery. Further, we considered other available data in this investigation.

In order to identify hidden, potentially predictive information in the data set, exploratory data analysis, univariate and multivariate/ cluster analysis techniques were applied using statistical analysis software such as SAS, combined with Geographic Information System (GIS) software.

The paper is organized mainly in two parts. The first part is a data mining study on production and treatment data to discover certain treatment parameters controlling production for both initial completion and refracturing; in the second part, we interpret those observation and findings from perspective of mechanism.

Introduction

In the Barnett, large-volume water fracs are a successful completion method that has resulted in superior production. The practice, when used previously in other shale reservoirs, did not generate the same magnitude of success as observed in the Barnett. Every shale reservoir is unique; however, the fundamental mechanisms that enable successful water fracturing in the Barnett likely apply to other reservoirs. Unfortunately, it seems much of the literature have not addressed fundamentals clearly.
Application of Advanced Mud Gas Logging for Improved Hydrocarbon Phase Determination in a Highly Depleted Reservoir
Authors: Crampin Tom , Gligorijevic Aleksandar , Clarke Ed , Burgess Jamie , Chung Shao-Jung
Published: May 2016

Downhole determination of hydrocarbon phase is a significant subsurface challenge in many highly depleted fields. Reservoir production results in fluid compositional changes and variable hydrocarbon saturation distributions. Standard petrophysical techniques such as analysis of density and neutron porosity logs can give misleading results under such conditions. Most commonly, oil reservoirs can display a neutron-density response indicative of gas. There is significant business impact in error of hydrocarbon phase determination. Mistakes can lead to poor completion decisions, incorrect reserves estimation and suboptimal well and reservoir management.

The fluid phase uncertainty resulting from interpretation of standard Logging While Drilling (LWD) datasets can be unacceptably high. Additional tools or techniques are therefore required. Downhole fluid sampling is one such technique. It is routinely and successfully acquired in exploration and appraisal wells and gives robust fluid phase determination. However, it is not economically feasible for frequent acquisition for in-fill production wells where low cost LWD acquisition is the norm. In addition, overbalanced wells drilled through highly depleted reservoirs lead to acquisition risk in stationary openhole logging techniques. Advanced Mud Gas logging (AMG) is an established tool for delivering real-time quantitative fluid composition in exploration, appraisal and early production wells. However, successful applications in highly depleted fields have not been published as AMG analysis can be complicated by compositional changes. In this paper we present a case study calibration of AMG with downhole fluid samples resulting in a robust, cost effective and safe tool for improved hydrocarbon phase determination in depleted reservoirs.

Introduction

Many techniques are used to determine hydrocarbon phase but all of them can be impacted by production related changes to reservoir fluids. The neutron-density "cross-over" is the most common gas identification tool (Figure 1). It results from an anomalously low neutron porosity reading in gas, due to low hydrogen index (HI), and an anomalously high density porosity reading, due to low fluid density. A second traditional technique is the neutron near count to far count ratio. The near detector reads largely in the near wellbore invaded zone where high mud filtrate saturation results in a high HI and a relatively low count rate when overlain with the far detector, which reads deeper into the formation, past the invaded zone, resulting in a relatively high count rate if gas is present.
Continental Carbonates as Hydrocarbon Reservoir, an Analogue Case Study from The Travertine of Saturnia, Italy
Authors: Ronchi Paola , Cruciani Francesco , Cirilli Simonetta
Published: May 2016

The Pleistocene Saturnia travertine represents an analogue of the pre-salt continental carbonate reservoir discovered on both sides of the South Atlantic margin. Two sub-horizontal travertine plates, few tens of metres thick and extended over an area of several kmsq, have been studied in 3D quarries exposures. The aim of this study was to reconstruct the facies variations and associate petrophysical properties applying an integrated multidisciplinary approach. The Saturnia travertine complex, due to warm waters spring still active in the area, is made of various stacked banks, separated by emersion erosive phases, showing alternation of lacustrine tabular bodies, terraces and sills. The facies association includes crystalline crust, pisoid, paper-thin raft, coated bubble, reed, lithoclast-breccia, micritic travertine. The d13C, ranging between +4‰ e +8‰, supports the CO2 volcanic mantel source, while the d18O from -5‰ and -9‰ is in agreement with warm meteoric water as for other travertine in the area. The Sr ratio isotopic signature is agreement with the carbonate derived from dissolution of Mesozoic deep seated carbonate. The facies reservoir properties have been studied through an integrated approach that includes porosity and permeability analysis on plugs, 3D X-Ray Computer Tomography, which evidenced the porosity connectivity, and image analysis on micro scale under thin section (microporosity) and macroscale on large rock slabs to define various porosity indexes (shape, roundness, pore size). A strong heterogeneity of the pore system and variable connectivity were pointed out. The porosity ranges from 4 to 30% and permeability is highly variable reaching hundreds of mD. The average pore diameter is between 1 and 4 mm, microporosity is low and the prevailing pore type is the inter-granular one. The study highlighted also that in travertine, the investigation should be conducted at a large scale in order to measure the large pores and wide scale connectivity.
Towards Improved Management, Interpretation and Integration of Dipmeter and Borehole Image Data
Authors: van den Heuvel Erik-Willem , Tengah Halimah , Goodall Tim , Pantic Dinah , Bal Adri
Published: May 2016

Historically in our industry, dipmeter and image log data, have generally bypassed the data management processes necessary to safeguard these data for future use. Brunei Shell Petroleum (BSP) is no exception to this, as concluded from a review of these data in 2011. BSP is perhaps one of the few E&P companies that has a significant amount of dipmeter and image data, more than 500 wells, exceeding 7000km, backdating to the early days of dipmeter tools, covering a wide range of historical recording mechanisms, computing platforms and principal databases. The current reality is that both raw and processed data are generally not readily available in a format usable by either petrophysicists or geologists. This is largely due to dipmeter and image tools having suffered a lag-time between tool evolution and effective data storage and archiving systems. As a consequence the potential value of the dipmeter and image logs has remained unrealized.

In 2012 BSP embarked on a Borehole Image (BHI) pilot improvement project consisting of some 54 wells, covering a wide range of dipmeter and image tools, with the objective to define data management standards and interpretation workflows aimed at effectively rescuing and ultimately ensuring full integration of this data. Integral to these improvements are recent advances in software capability to handle dipmeter and image log data. Our system and procedures allows for initial data QC and saving a "ready-for-interpretation" data subset available from our corporate data store.

Petrophysicists and geologists, who might not have the expertise to QC raw image log curves (maybe up to 30 curves types), now have the confidence to import and use the ready-for-interpretation dataset into Techlog. Legacy image logs are readily available for multi-well studies, reservoir correlation, structural ties to seismic, net-pay calculations over thin bed heterolithic intervals and facies logs for reservoir characterization.
Gas Drilling Wellbore Stability Analysis in Igneous Rock Carboniferous System of Dzungaria Basin
Authors: Wang Zonggang , Zhao Hongshan , Feng Guangtong , Han Laiju
Published: May 2016

During drilling operation in carboniferous system of Dzungaria basin, igneous rock was met, which leads to a low penetration rate and long drilling cycle, because of large thickness, high hardness and poor drillability of the igneous rock. Quasi-three axis confining pressure experiment was carried out with the igneous rock core of WUCAN 1 well. Experimental results showed that the igneous rock keeps a brittle fracture even in the confining compression pressure of 40MPa. Based on Mohr-Coulomb failure criterion, one analysis method about the applicability of gas drilling was put forward through comparing maximum principal stress while wellbore instability happened with upper-cover pressure. It can be concluded that gas drilling technology can be applied in carboniferous igneous strata of Dzungaria basin, when embedding depth is less than 6110 meters, which provides theoretical basis on the application of gas drilling technology in deep exploratory wells whose target zone is in igneous strata of carboniferous system of Dzungaria basin.

Introduction

After the discovery of SHIXI oil field and DIXI oil field in recent years, in the western new area of SLOF, SINOPEC, strata of carboniferous system are considered to be high potential. So several deep exploratory wells are mapped out by SINOPEC, including WUCAN 1 well. However, from current data, stratum of carboniferous system is mainly igneous rock, which has large thickness, high hardness and poor drillability. It leads a low mechanical drilling speed and a long drilling cycle. For WUCAN 1 well in the northern part of Dzungaria basin, conventional slurry drilling method is applied from well depth 4286 meters to 6323.6 meters. Many new technology solutions were successively used to enhance the drilling speed, such as ‘high efficiency roller bit + screw rod’ composite drilling, ‘Diamond head pregnant bit + high speed screw rod’ composite drilling, high frequency torsion impact drilling tools, waterpower impulse injector + high efficiency drilling bit of Baker Hughes. The results aren't pleased: average drilling speed is only 0.72m/h, and the drilling cycle is 239 days, which is more than half of the whole well cycle.

In the same stratum, compared to conventional slurry drilling technology, drilling speed and bit life can be highly increased by gas drilling technology [1–4]. So the application of gas drilling technology in igneous rock of carboniferous system in Dzungaria basin can be a possible way to overcome the bottle neck of drilling speed. Field engineering application shows that borehole stability is the main problem in gas drilling technology[5–7]. In this paper, mechanical properties of the rock nearby well wall are experimental investigated by quasi-three axis compression test, to evaluate gas drilling technology applicability in the igneous stratum of carboniferous system in northern Dzungaria basin.
Effect of Barriers on the SAGD Performance Result
Authors: Zhou You , Xi Changfeng , Wu Jian
Published: May 2016

The barriers in oil reservoir have great effect on SAGD production. Due to wide existence of interlayers, steam chamber can not move upward freely in perspective of chamber development, and also leads to a longer SAGD production cycle so as to increase the investment risk. Firstly the author studied the distribution and formation reasons of muddy barriers in the Zhong 32 of Windy City oilfield. Steam chamber developing characteristics and steam breakthrough pattern are studied by temperature detection data, historical data and microseismic data fitting dynamic data binding static geologic data. Barriers have three relative position relation with SAGD horizontal well. The order sorted by barrier influence to production from high to low degree: injection well inside barriers, between injection and production wells, above injection well. The results showed that the barrier pattern of Zhong32 is physical barriers, with characteristics of high shale-sand ration, low permeability, poor blocking ability. The horizontal continuous barriers increased steam channeling risks thereby control vapor liquid interface more difficult. Double tubes steam injection and artificial lift can be beneficial for the stable steam chamber operation, increase oil production and decrease water cut. High pressure steam operation increases the opportunities of barriers breakthrough by steam and obtains high oil production per day. The pattern of steam breakthrough in muddy barriers can be divided into bypassing and traversing.
Discussion on Unconventional Petroleum Reserves Classification and Evaluation in China
Authors: Bi Hai Bing , Wang Yong Xiang , Wu Guo Gan , Zhang Junfeng , Duan Xiao Wen , Sun Guang Bai
Published: May 2016

Preface

E&P of unconventional oil and gas becoming wider and wider, reserves classification and evaluation methods of unconventional oil and gas resources are discussed and improved further, which has become the focus of related international conferences in recent years.

In China, based on the requirement of CBM development, relevant rules of reserves classification or calculation have been formulated at enterprise and industry levels in recent years.

But in general, these rules are just the continuation of traditional reserves classification system which mainly focuses on the OGIP classification and evaluation, and considers less on unconventional oil and gas characteristics (such as geological features, particularity of developing techniques and marginal economy, etc).

Furthermore, conflicts between reserves and mining right management are becoming prominentgradually, which affects the E&P of unconventional oil and gas in China to some extent.
A Novel Approach to Water-cut Prediction in Deep Cambro-Ordovician Tight reservoir with Complex Hydrocarbon Charge, Diagenetic and Structural Growth Histories
Authors: Mohsin Labib , Al Busaidi Salam , Aljiroudi Fadi , Al Lawati Mohammed
Published: May 2016

In deep tight shaly-sand reservoir, with complex hydrocarbon charge and structural growth history, it is difficult to characterize reservoir zones with high water cut from others with low water cuts and high hydrocarbon production rate, due to high resistivity readings of tight reservoirs.

Deep reservoir "B" in Abu Butabul Field, NW Oman has been charged via two genetically and chronologically different hydrocarbon phases (oil then gas); during a complex deep burial digenesis and structural trap history. Due to the variation of Hydrocarbon properties of such tight reservoir, it has been difficult to analysis such a reservoir using conventional petrophysical evaluation methods.

In this study, a modified version of the approach published by Ibrahim, Abd_Elmoula, Said Hasani, Sultan, Jahwari in SPE 130261 in which Ro (Resistivity of Rock saturated with Formation water) and SWirr (irreducible water saturation) used to distinguish water from hydrocarbon zones has been taken a step further in order to predict water cut in tight reservoirs (illustrated in the workflow below).

After calculating wireline logs derived permeability, there are two elements to be calculated: KHw (Permeability of sands units filled with water * thickness of these sand units), and KHhc (Permeability of sands units filled with hydrocarbon *thickness of these sand units). The ratio of KHw/(KHhc+KHw) provides a mean of estimating percentage of the expected water production. This approach has been validated with actual water cut from production data.

Using mathematical product of KHhc*Phie (effective porosity)*(1-SW) provides a mean to rank the wells in terms of expected Hydrocarbon productivity, which then can be contoured and utilized for reservoir fracturing program of the reservoirs in promising wells.
Integrity Management of a Complex LNG facility
Authors: Zaki Mohammad , Sijm Albertus
Published: May 2016

Description

RasGas Company Limited ("RasGas") employs a Facility Integrity Management System (FIMS) whose primary objective is to create a frame work system to maintain the physical and functional integrity of RasGas critical assets.

Programme design starts with grouping equipment by programmes aligned with equipment classes such as structures, pipelines and machinery. Equipment is prioritised by determining its criticality to operations based on health, safety, environment (HSE) and business consequences. Risk-based plans, the so called equipment strategies, are developed to mitigate risks and maintain the desired level of integrity and reliability. These equipment strategy activities are then built into an overall Integrity Programme that includes objectives, roles and responsibilities and practices to ensure operational integrity through the operating life of the equipment.

This paper will explain the various aspects and objectives of the system, in particular the benefits of having such a framework in place, managing risk-based inspections, early risk identification, the continuous improvement cycle through data analysis and risk screening non-performed preventive maintenance activities.

The Facility Integrity Management System within RasGas would be described with the challenges faced and the lessons learnt during implementation. Challenges in the programme design, development and implementation will be highlighted as well as the strategies and decisions made to overcome these. Particular focus will be given to learnings in the development, implementation and sustainment of equipment strategies, early risk identification and system management.
Low-Salinity Polymer Flooding: Improving Polymer Flooding Technical Feasibility and Economics by Using Low-Salinity Make-up Brine
Authors: Vermolen Esther C. M. , Pingo Almada Monica , Wassing Bart M. , Ligthelm Dick J. , Masalmeh Shehadeh K.
Published: May 2016

Polymer flooding is a mature EOR technique, which is successfully applied in both sandstone and carbonate reservoirs. In ongoing polymer projects, make-up brine is either formation water, sea water or any available water sources like deep or shallow aquifers. In this paper we focus on the use of low salinity water as the make-up brine. The objectives of combining low salinity flooding (LSF) with polymer flooding are three-fold:Using low salinity brine reduces the amount of polymer required to obtain the target viscosity, which may lead to significant cost reduction.Combining the benefit of low salinity flooding with polymer flooding leads to higher oil recovery over conventional polymer flooding.Enhancing the elasticity of polymers by using low salinity brine which may lead to reduced Sorw and increased oil recovery.

In addition to the objectives mentioned above, the use of a low-salinity make-up brine can give other benefits, such as better polymer stability (especially at high temperatures), lower sensitivity to polymer shear degradation, lower polymer adsorption and lower scaling and souring tendency.

The paper will presentExperimental procedures for investigating the potential benefits of low salinity polymer on both the required polymer concentration and the oil recovery.Experimental results for several field casesDe-risking activities that were undertaken to mitigate any potential negative impact of using low salinity polymer, in the areas of clay swelling, polymer shear sensitivity, mixing and adsorption.

The paper concludes that low-salinity polymer flooding can significantly improve existing and anticipated polymer flooding projects by reducing polymer volumes and/or increasing oil recovery. Low-salinity polymer flooding provides opportunities to apply polymer flooding in high-salinity and high-temperature reservoirs, for which polymer flooding with produced or formation water would be technically unfeasible or uneconomic.
The Applications of Laser Technology in Downhole Operations - A Review
Authors: Adeniji Adewale Wasiu
Published: May 2016

Downhole operations in the petroleum industry include drilling and completing the well for production. Experiments conducted on different types of lasers have shown the potential of the cutting - edge technology being applied in downhole operations. One of the tests was conducted on MIRACL (Mid Infrared Advanced Chemical Laser) to determine its feasibility for drilling and perforating petroleum wells and another was on COIL (Chemical Oxygen-Iodine Laser) to determine the least specific energy (SE) needed to destroy varying rock types. This paper presents the applications of laser technology in downhole operations such as drilling, perforation, stimulation, vaporizing stuck pipes, tracer detection, treatment of asphaltene deposition and cutting of subsurface equipment such as casings, tubing strings etc. Its benefits are presented in terms of effects on Rate of Penetration (ROP), operational downtime, formation damage, clay treatments, flow enhancement and overall well deliverability. Laser technology has been utilized successfully in the medical industry, manufacturing industry, nuclear industry etc. Therefore, its applications in downhole operations are major strides in the petroleum industry and a means of optimizing downhole operational practices. It has been reported that integrating laser technology with conventional drilling technology will immensely improve drilling efficiency but this has not been so far applied in the field. Conclusions derived from a two year project funded by The Gas Research Institute (now Gas Technology Institute) in 1997 on "Adapting Star Wars High-Powered Lasers to Drilling Natural Gas Wells," are that lasers can cut rock of all lithologies; shear power shares importance in cutting rock with such parameters as wavelength, purge gas pressure and hole size; and historical and widely accepted theoretical calculations of the laser power needed to spall (break), melt and vaporize rock are significantly higher than experimental values. Just like any new technology, laser technology has its challenges and they are highlighted accordingly.

Introduction

The most reliable way to detect oil and gas is by drilling an oil well. From the onset, oil wells have been drilled using cable tool (percussive) drilling method. This method of drilling was gradually replaced by rotary drilling in the twentieth century. As Research and Development progresses, laser drilling was developed in the 90's. An oil well needs to be completed to flow the well. Well completion includes casing, cementing, perforation, stimulation etc. Various studies have been conducted to evaluate the suitability of this breakthrough technology in downhole operations and they have all yielded positive results.
Gtl Efficiency
Authors: Al-Tamimi Abdulaziz
Published: May 2016

A number of key parameters have been used for defining the efficiency of GTL (Gas-to-Liquids) process. The most commonly used bases are Carbon Efficiency (CE) and Thermal Efficiency (TE). This paper discusses the definition of each of them and the significant developments that have occurred and have been expected on the key focus areas of GTL efficiency improvement.

Both CE and TE should be maximized to the extent of technically feasibility and economical justification to ensure responsible and sustainable utilization of natural resources. Nowadays, the GTL technology CE and TE are considered drawbacks of the GTL technology and as a consequence considerable efforts are being made by technology developers to reduce the inefficiencies.

The current generation of the GTL technology has a typical plant wide CE of 70–75 % and a typical plant wide TE of 57–61%. Although GTL efficiency is still low compared to conventional refineries and LNG plants, it has been improved significantly over the last two decades.

Further improvement can be expected over time as the GTL technology has not gone through the same degree of technological improvement as the conventional system. Advances in GTL technology are projected to increase the efficiency within the next decade as such it would be comparable to conventional refineries and LNG plants that have CE and TE of around 90% and 73% respectively.
Multiphase Flow Meters Trial Testing in High GOR/GVF Environment
Authors: Nasri Ahcene , Al-Anizi Abdulaziz , Al-Amri Meshal A. , Al-Khelaiwi Faisal T. , Al-Anazi Ammal
Published: May 2016

Multiphase flow metering (MPFM) technology is gaining popularity and becoming the main well rate testing mechanism in some regions of the world. Yet, their application in measuring the flow rates of high gas-oil-ratio (GOR) and/or high gas volume fraction (GVF) wells has always been a challenge. A remote field located in the Southeastern part of Saudi Arabia commenced its production in the late 90's from a thin oil column lying between a large gas-cap and a water aquifer. Although, 84% of the thin-oil-column producing wells are horizontal and multilateral wells with extended reservoir contact, the gas-cap gas breakthrough and production from these wells have increased gradually; resulting in an increase in the wells GOR. Currently, 35% of the wells are producing at high GOR ranging between 2,000 and 6,000 SCF/STB with a GVF reaching as high as 98%.

The fluid flow rate tests of these wells are conducted through a test separator designed to handle a GOR of 2,500 SCF/STB; well below the current GOR of these wells. Such plans require identification of the most appropriate MPFMs that can operate successfully in such high GOR/GVF conditions.

This paper describes the field trial test of three MPFMs under high GOR/GVF conditions of dry and wet production. The meters' performance is compared to a portable test separator properly sized to accommodate the high gas and liquid flow rates of the producers of this field. The paper summarizes the results of this test and justifies the measurement errors in light of the operating principle of each meter. The paper also provides valuable guidelines for conducting such testing operations by building on the lessons learned from this trial test.
Ultrafast Determination of Archie and Indonesia m&n Exponents for Electric Log Interpretation: a Tight Gas Example
Authors: Bona N. , Rossi E. , Bam B.
Published: May 2016

It may take several months to measure the Archie or Indonesia parameters of a tight rock. As a result, a long time elapses between the acquisition of electric logs and their final interpretation. We describe a method that provides reliable measurements of these parameters in one day. The method combines NMR and electrical determinations. The latter are performed using a patented 4-contact cell. A description of method is given and a tight sand case study discussed.

Introduction

Resistivity Index (RI) is defined as the ratio of rock resistivity at any given water saturation (Sw) level to its resistivity when completely saturated with water. All labs measure RI at a number of different average saturations. The greatest source of error in these measurements is the heterogeneity of Sw. Even a small Sw heterogeneity may have a strong effect on RI test results and can translate into significant errors in the log-derived saturations.

Consider, for instance, the rock sample sketched in Fig.1. The sample is comprised of two regions having different saturations. Let Sw1 be the saturation of the higher Sw region and a·Sw1 the saturation of the lower Sw region (0<a < 1).
Dukhan Field CO2 Injection EOR Pilot: Reservoir Modeling & Planning
Authors: Ozen Ozgur , Wahlheim Thomas A. , Attia Tarak , Barrios Levin , Bin Ab Majid Mohamed Naguib , Wilkinson John
Published: May 2016

A reservoir study was conducted to plan a near-miscible CO2 gas injection pilot in the Dukhan Field with the following study guidelines:Determine overall objectives and timeframe for the pilotDesign the pilot to meet the objectives and timeframePlan the pilot in a portion of the field with representative reservoir descriptionPropose a surveillance and monitoring plan to ensure high quality information is obtained for interpreting the pilot performanceDesign the pilot so the recovery processes are scalable to larger well spacing for reservoir-wide application

Using these guidelines, the following pilot objectives were developed:Provide data on well injectivity and productivityReduce uncertainty in the estimation of incremental oil recovery from CO2 gas injection relative to waterfloodProvide data to allow commercial scale well and facility CO2 gas injection designMinimize the impact on current operations outside the pilot area

The results of the reservoir modeling study provided the detail for well orientation and placement to satisfy the pilot objectives at a reasonable cost and within appropriate timeframe for information gathering, analysis, and commercialization decisions. The reservoir model pilot area selected is one kilometer square segment in a crestal structural location that does not contain active wells and is near existing surface facilities. The reservoir description data used for the segment models were extracted from history matched full-field reservoir models. The proposed pilot wells are located within close proximity of each other to achieve gas breakthrough and oil bank arrival within the proposed pilot evaluation period of two years. The pilot design ensures that the pilot would allow for data gathering of key project design information; such as injectivity, gas breakthrough timing, oil displacement, and reservoir sweep.

Introduction

The large, mature Dukhan Field is located onshore Qatar, approximately 80km west of Doha. It is a north-south plunging anticline approximately 70km long by 8km wide. The field was discovered in 1939 and first production occurred in 1949. The field has more than 750 well penetrations. The major oil reservoirs are the Upper Jurassic Arab C and Arab D. There are lesser amounts of oil and gas in the Middle Jurassic and non-associated gas in the Permo-Triassic Khuff formation. The Arab C reservoir was initially filled with over 1400ft of oil between the structural crest and the oil-water contact. The Arab D reservoir was initially filled with over 700ft of oil rim in equilibrium with 700ft of gas-cap.
Fibre Optic Sensing For Improved Wellbore Production Surveillance
Authors: van der Horst Juun , Den Boer Hans , In 't Panhuis Peter , Wyker Brendan , Kusters Roel , Mustafina Daria , Groen Lex , Bulushi Nabil , Mjeni Rifaat , Awan Kamran Fahmeed , Rajhi Salma Mohammed , Molenaar Mathieu M , Reynolds Alan , Paleja Rakesh , Randell David , Bartlett Richard , Green Kevyn
Published: May 2016

Since our previous publication1 significant progress has been made to further mature the application of Fiber-Optic (FO) based Distributed Acoustic Sensing (DAS) for production and injection profiling. A considerable number of new field surveys were conducted to further improve the evaluation algorithms or workflows which convert the DAS noise recordings into flowrates from individual zones. For gas producing wells, a new graphical user-interface has been developed that allows the user to visualize and QC the data in real time. Additional flow and visualization software have been developed for single phase gas producers to enable the user to select and evaluate the data in a user-friendly manner using the most up-to-date evaluation algorithms.

There are still improvements to be made in enabling Distributed Sensing infrastructure, such as handling and evaluation of very large data volumes, seamless FO data transfer, the robustness & cost of the FO system installation, and the overall integration of FO surveillance into traditional workflows. It will take some time before all these issues are addressed but we believe that FO based applications will play a key role in future well and reservoir surveillance.

In this paper we present two recent examples of single-phase flow profiling using DAS. The first example is from a single-phase gas producer in one of the Unconventional plays in North America and the second example is from a long horizontal, smart polymer injector operated by Petroleum Development Oman (PDO).

Introduction

In oil and gas field development there is often a lack of high quality Well and Reservoir Surveillance (WRS) data for quality decision making; leaving significant reservoir or well performance uncertainties potentially leading to suboptimal reservoir development. The need for frequent and good quality surveillance data is highest in complex reservoir developments such as Unconventional plays, waterflooded reservoirs, Thermal and Chemical Enhanced Oil Recovery (EOR) projects. One of the reasons that well surveillance data is not acquired in practice is that it often causes significant production deferment. Another reason is that often the data gathering surveys are expensive or create large operational risks associated when using conventional logging methods, particularly in high rate, highly deviated or long horizontal producer wells. In some cases, the small diameter production tubing limits access to the well with conventional logging tools.
Processing and Preliminary Interpretation of the Ultra High-Density Full-Azimuth 3D Seismic Survey, Dukhan Field, Qatar
Authors: Seeni Salvarajeh , Setiyono Kriyanti , Zaky Hala , Snow John , Weber L. James
Published: May 2016

The Dukhan Field 3D seismic survey is an ultra high-density wide azimuth survey (i.e., point source and receiver, short source and receiver line interval, and full azimuth recording) intended to provide a significant uplift in quality and resolution to enable the imaging of reservoir sub-layers and fine-scale structural features.

This paper presents the challenges and lessons learned from full-field processing and inversion. Seismic interpretation demonstrates added value to the field, which leads to improved reservoir models and support to well operations through improved well placement. Subtle structural, stratigraphic, and diagenetic features are now imaged.

Knowledge gained from processing this survey includes:cost, time, and effort invested on the Dukhan 3D survey is worthwhile as high quality results are obtained at 15m bin processing;3.75m bin processing is now possible, and could be performed to improve image quality over the full seismic bandwidth for all reservoir intervals;Pre-Stack Depth Migration (PSDM) workflow is recommended for optimal offset and azimuth reconciliation and noise attenuation;the adverse effect of near-surface geologic variability on seismic data quality can be improved by utilizing microgravity and resistivity (Vertical Electrical Sounding) techniques; andproper preconditioning of the input data is critical for reliable prediction of reservoir properties away from well control.

While industry's knowledge and experience in acquisition and field operation of ultra high-density full-azimuth seismic has increased over the last 3 years, processing of such data to ensure optimal imaging and reliable reservoir property predictions (e.g., porosity) has lagged. QP believes that lessons learned through this round of processing can provide insight for prediction of rock properties in the major Dukhan reservoirs.

Introduction

The Dukhan field is located along the south west coast of Qatar, extending 70 kilometers north-south (Figure 1) and is one of three giant oil and gas fields in which Qatar Petroleum (QP) retains 100% interest. It was discovered in 1939 and has produced from three oil reservoirs (Arab-C, Arab-D, Uwainat) and one gas reservoir (Khuff). It is the only onshore field in Qatar and more than 750 wells have been drilled to date. Over the past 70 years, the hydrocarbon development and production history at Dukhan has undergone several phases. Initially, the oil and gas reservoirs were produced using natural pressure depletion. Water injection was started in the mid to late 1960's as pressures begin to fall. A more efficient power water injection system and horizontal well technology were introduced in the late 80's.
Modeling Tectonic Heat Flow and Source Rock Maturity in the Rub
Authors: Abdul Fattah R. , Meekes S. , Bouman J. , Ebbing J. , Haagmans R.
Published: May 2016

A 3D basin modeling study was carried out to reconstruct the regional heat flow and source rock maturity in the Rub'al-Khali basin. Gravity gradient data from the GOCE satellite were used to model deep structures, such as the Moho interface. Tectonic heat flow was modeled using the GOCE-based Moho interface to reflect heat flow variations in the basin though time and space. The thermal maturity of Silurian and Jurassic source rocks in the Rub'al-Khali was calculated using the GOCE-constrained basal heat flow model. GOCE-based Moho depth map was calibrated to data from known seismic stations in the region. This map provided input to constrain the heat flow in eth basin. Modeled heat flow values are consistent with known values of heat flow in the region. The model indicates that the Silurian and Jurassic source rocks are generally in the hydrocarbon generation window and the modeled maturity trends are in agreement with the observations in the area.
Developing disruptive and revolutionary new generation seismic technologies for the Middle East
Authors: Hwang Jay , Baeten Guido , Walk Wim
Published: May 2016

Extended Abstract

We present the business and technical underpinning for developing revolutionary onshore and offshore seismic acquisition technologies in order to meet the challenges of the new E&P business portfolio. In this paper we will also describe new seismic acquisition systems developed with external technology partners and report their progress. These new systems aim at disrupting both the onshore and offshore seismic industry by delivering accurate and high quality seismic data with significant cost improvement. For land Shell is pushing toward a million channel system development in order to drastically drive the cost down with high receiver and source efficiency, and strongly improve the seismic quality with WAZ, long offsets, and broad bandwidth for surface seismic. This system also targets permanent reservoir monitoring. For offshore applications, a multi-source fast deployed ocean bottom node (OBN) system is being developed to drastically reduce the survey cost such that it can be cost effectively applied to large exploration surveys as well as higher resolution surveys for 4D. Shell expects to commercialize these new technologies with partners in order to deploy them to Shell assets in the nearer term and to the industry in the longer term.

Introduction

Remaining onshore conventional exploration targets tend to distribute in areas where reservoirs are associated with structurally complex geology or lie beneath highly variable near surface or structurally complex overburden. With unconventional hydrocarbon opportunities, delineating sweet spots presents even more challenges. Current seismic acquisition and processing techniques are insufficient to characterize these difficult reservoirs. Seismic images with a quality similar to those emerging from offshore environments are necessary for better exploration and production decisions in these challenging onshore areas.
E-Technology: A Key for Excellence in Training Geosciences
Authors: Dekeyser Dominique , Machhour Louai , Vedrenne Valerie
Published: May 2016

Training is a major challenge in oil &gas companies because of the rich diversity of cultures and generations. Since our aim is to provide the same skill development opportunities to every Total employee, we need to develop a worldwide access to quality training that is up to our standards. The expected high rate of seniors' retirement imposes the need to find ways of preserving departing experience. Our technical studies are complex and use concepts and tools that rapidly develop with time. Training must address these issues, and be provided faster and at lower cost.

Traditional classroom courses need to be reconsidered in the light of these requirements and of the development of new technologies, as far as computing and pedagogical aspects are concerned. Furthermore, Total has developed a personalized internal apprenticeship and a training path, supported all along the career, which combines technical and personal development.

The search for fit-for-purpose new ways of training leads us to promote: – Distance learning studios to share specialists' know-how (e.g. distant coaching from our Headquarters Training rooms), – Course capturing and broadcasting to build on experts' experience (e.g. preserving the knowledge of departing seniors), – New in-the-field geosciences pedagogy with interactive tools (e.g. richmedia resources to enrich courses on the field), – Immersive training techniques to become operational more quickly (e.g. interactive drilling rig) – Fast learning modules (e.g. e-learning) monitored on in-house training platform.

In other words we are experiencing a revolution in training content and training media. The learning process is based more and more on "real life" situations and modular courses to gain in flexibility. The presentation gives detailed and practical examples of these new tools that are targeted towards our geosciences technical staff worldwide.
Innovative Well Intervention Techniques to Sustain Production in Mature Offshore Fields
Authors: Koshy Noble Sam , Anand Saurabh , Vadapally Sai Rakesh Varma
Published: May 2016

Cairn India is an operator for two mature offshore fields in India – Ravva and CB/OS-2. Due to high offshore rig cost combined with cost recovery risks, innovative well intervention techniques are implemented in both the fields to sustain production & enhance injection. This paper summarizes some of the successful well intervention cases over the past few years and how it changed the approach towards meeting production targets.

Case 1: Slickline conveyed straddle gas lift technique to activate and produce from a previously shut-in well.

Case 2: Wireline conveyed robotic tools to retrieve downhole screen and restore well injection.

Case 3: Modular CT units and advanced downhole tools for well stimulation improving production by multiple folds.

Case 4: Specific chemical system to successfully complete a vessel based stimulation campaign in water injectors; this led to an overall two-fold increase in the field injection rates.

Case 5: Advanced downhole camera to identify wellbore held-up reasons during regular interventions and how it has led to several important decisions saving time and cost.

The operator always looked at challenging problems as opportunities for innovative solutions. The above interventions were focused on well revival using cost effective and innovative well intervention techniques avoiding rig based workover and achieving the objective in all the above cases. A synopsis on the recently completed cases and future inventive solutions is covered in last section of the paper.

Field Introduction

Ravva is located 10 kms off the shore of Godavari Delta on the east coast of India. The anticline structural reservoirs are multi-Darcy sands of Middle Miocene age. The field oil is light with an API gravity of 35o and GOR of the range 470 – 520 scf/bbl. The field was developed through 8 unmanned platforms with production commencing in 1993. Water injection was introduced in 1997 for reservoir pressure management and is the supporting drive mechanism. Water-oil displacement characteristics are excellent due low oil viscosity, high permeability, low residual oil saturation and good areal pressure communication. Almost all wells are producing with Gas injection for artificial lift. After a sustained plateau production period of 50,000 bopd, the field currently is on decline with increasing water cut (average water-cut ranging from 60% - 90%).
Fracture and Wellbore Spacing Optimization in Multistage Fractured Horizontal Wellbores: Learnings from Our Experience on Canadian Unconventional Resources
Authors: Ziarani Ali S. , Chen Cheney , Cui Albert , Quirk David James , Roney Dana
Published: May 2016

Horizontal wellbore drilling and completion technology with multi-stage fracturing has revolutionized the exploitation of unconventional resources in North America in recent years. Many unconventional oil and gas reservoirs with ultra-low permeability have become economical as a result. Yet, the development and completion costs of these resources can be further improved by optimizing the number of fracture stages placed on each wellbore and the number of wellbores drilled per section of land.

This study highlights our operational and analytical experience on an integrated workflow for optimization of fracture and wellbore spacing to develop the unconventional resource in Western Canadian Sedimentary Basin. The study is based on fracturing design and optimization, microseismic fracture mapping, reservoir modeling and production analysis for over 30 case studies on different formations in Canada including Montney, Cardium, Doig, Beaverhill Lake, Viking, and Sprit River formations.

The typical workflow for fracture and well spacing optimization studies includes multiple and iterative steps: minifrac tests, fracture modeling and calibration, fracture job execution, microseismic monitoring, reservoir simulation and production data analysis. In this integrated process, hydraulic fracture models were built based on fracture job data, rock mechanics and log data, and then calibrated with minifrac data and microseismic fracture mapping results. Three dimensional reservoir simulation models were constructed using laboratory core data, petrophysical and geological data, and reservoir fluid PVT properties. The calibrated fracture models were integrated into reservoir simulation models. The reservoir models were fine-tuned by history matching the production data. The fine-tuned models were then used to run multiple scenarios by varying the number of fracturing stages per wellbore and wellbores per section. Fracturing treatments with different pump rate, proppant size, pumping schedule and proppant tonnage were further investigated to optimize fracture geometry and conductivity for production enhancement. Optimal fracture and wellbore spacing scenarios were recommended for future drilling and completion planning in the field.

Such optimization studies have helped to minimize operation cost and improve the economics of resource development. Our workflow and experience in West Western Canadian Sedimentary Basin can be a useful guideline to improve economic success of unconventional resources in other basins around the world.