bluuebunny/crossref_metadata_2025 huggingface dataset:
Overcoming Drilling Challenges in Highly Fractured HP/HT Formations
Authors: Al-Ghamdi Magid A. , Baggal Zaki , Assiry Ali , Omini Eno
Published: January 2010

Drilling in highly fractured, high pressure, high temperature gas fields presents various drilling challenges including loss of circulation, gas kicks and hole instability due to the presence of fractures, reactive shale and abnormally pressurized formations.. The original design of the wells was modified to meet these challenges and improvements have been successfully implemented.. These improvements include changes to the original well design, drilling fluid design and drilling practices and these improvements have reduced the problems that were encountered in the troublesome 16”, 12”, & 8⅜” hole sections.. This paper will discuss the different solutions implemented and other solutions being investigated to eliminate the drilling difficulties encountered while drilling HP/HT formations in deep hole sections.
Productivity Impact from Geochemical Degradation of Hydraulic Fractures
Authors: Weaver Jim , Rickman Richard
Published: January 2010

The generation of hydraulically produced fractures that are kept open by the use of proppants is a key technology that enables economic production from deep gas reservoirs. Much laboratory attention has been given to the study and prediction of the early productivity of wells completed with this method. Interactions of formation fluids and frac fluids with formation rock and proppant can lead to a host of productivity-reducing mechanisms. Frac fluid damage, scaling, proppant conductivity loss, proppant crushing, and proppant embedment are some of the variables studied in short-term experiments. Little effort, however, has been directed towards the long-term study of these mechanisms on fracture productivity in a laboratory setting.

This paper presents the results of extensive laboratory testing aimed at understanding the interaction of water composition, formation composition, proppant composition, temperature, and closure stress that permit the modeling of certain diagenetic reactions that result in accelerated fracture conductivity loss with time. Some experiments demonstrate that, under certain conditions, the impact of diagenetic reactions on conductivity loss can be significantly reduced by coating mineral surfaces with protective organic films.

This work clearly demonstrates that proppants can react with formation minerals and result in creation of fines, reduction in permeability, and loss of proppant crush strength. This chemistry should be used in selecting proppant that will provide the most sustained productivity. Sustained fracture conductivity can also be achieved under certain conditions by the use of organic filming agents.
First Successful Tight Gas Reservoir Completion and Fracture Stimulation in Sarah Formation, Rub Al-Khali Empty Quarter of Saudi Arabia
Authors: Bu-Khamseen Raid , Khakimov Ayrat , Sierra Leopoldo , Young Dustin , Machala Mark
Published: January 2010

Lukoil Saudi Arabia started a tight gas exploration campaign in the Rub Al-Khali Empty Quarter in 2006 and nine wildcat exploration wells have been drilled and evaluated. These prospective tight gas discoveries in the Empty Quarter have occurred in High Pressure and High Temperature (HPHT) horizons at depths between 12,000 and 20,000 feet, where the stress and temperature are extremely high in addition to micro-Darcy levels of reservoir permeability. This has made the exploration activity more challenging.

To overcome the extreme challenges and to help assure the success of the exploration activity, a new drilling, completion, and fracturing strategy was implemented in one of the most recent wells. The synergy of the new strategy steps resulted in the first successful discovery in the Sarah formation.

This paper presents the open hole compartmentalized completion steps, as well as the selective fracture stimulation strategy and challenges that have lead to the first successful tight gas discovery in the Sarah formation.
Saturation Calculation in Volcanic Reservoirs––A Case Study for Haer Jin in PetroChina Jilin Oilfield
Authors: Yang Xing wang , Zhang Dawei
Published: January 2010

The SongLiao basin, in north-eastern China, is one of the largest oil and gas basins in China. The volcanic Reservoir underlying the conventional oil bearing and sedimentary reservoirs of SongLiao basin is proven to be huge gas-bearing reservoirs. One deep gas-bearing volcanic reservoir called HaerJin field in the south of SongLiao basin was found recently. As a result of this new find, a joint study project was initiated to perform an evaluation of all available data from existing and new wells, with the objective of calculating gas in place.

The lithology features of the volcanic reservoir of Haer Jin structure are described and the main problems faced are saturation evaluation. Resistivity based methods for saturation analysis have proven to be unsuccessful for this kind lithology. Based on the study on large numbers of core data and the relationship between CMR T2 distribution and capillary pressure curves, one method which has been employed in the study is the calculation of pseudo capillary pressure curves from CMR T2 distributions, and calculation of saturation from the resulting capillary pressure curves.

In the volcanic gas reservoirs, it is difficult to get the formation fluid saturation and gas-water contact from conventional wireline logging data, because of the complicated volcanic mineral composition and petrophysical properties. For the first time, the FWL (Free Water Level) of volcanic reservoir is successfully estimated based on pressure data analysis, which improves the calculation of fluid saturation based on pseudo capillary pressure curves from CMR.

The accuracy and applicability of this formation evaluation approach was proved by the following new drilling wells. The significance of this study is to open one idea for formation evaluation in unconventional reservoir.

This paper will focus on saturation evaluation of the volcanic reservoir in Ha'erJin of the southern Songliao Basin, PetroChina Jilin Oilfield.
Oman, 27/8" Velocity Strings in Deep and Tight Gas Wells
Authors: Goedemoed P. , Al Muselhi F. , Al Manji A.
Published: January 2010

In Oman, many of the gas reservoirs are deep and rich in gas condensate. The deep gas reservoirs require multiple fraccing to enable economical production. The gas and condensate production of the deep gas field described in this paper started in 1999. Since 2007, liquid loading is becoming a growing issue at current flowline conditions. Although compression is scheduled in 2010, some wells still require smaller tubing sizes to enable stable gas production. At current 9,000 kPa flowline conditions, the gas wells start liquid loading in the region of 160 −190 e3m3/d. The installation of a velocity string (VS) stabilizes the gas and condensate production in wells producing < 200 e3m3/d to as low as 50 e3m3/day. As the production life cycle is extended, velocity strings will increase the ultimate gas recovery. In the year 2008/2009 five VS were installed. Production data is available and helps in understanding liquid loading and the modeling of multi phase flow behaviour in deep gas wells.

The installation of VS in the Oman Deep Gas field is challenging with respect to its great depth and materials being used. The first VS was installed in a live well in September 2008. Under-balanced installation was identified to be crucial in preventing formation damage in depleted and low rate wells. Some crucial lessons were learnt and solutions were found for all technical and operational challenges. The VS exceed a depth >4500 mTVD and have ~100,000 lbs string weight hung-off on a single retrievable packer system. It was also the first CR13 P110 string ever been snubbed into a live well. This paper describes the first VS trials done in Oman deep gas field, the inflow/outflow modeling and the main operational challenges encountered.
Successful Application of UBD/MPD Technologies for Reservoir Characterization and Drilling Performance Improvement in Deep Gas Formations—Saudi Arabia
Authors: Jiang Qin , Wu Winston , Viera Paco , Russell Bob
Published: January 2010

The proposed well was planned as a vertical exploratory well, which located in the eastern part of a block in Kingdom of Saudi Arabia. Several wells had been drilled in this area by the same operator. The offset drilling data and information show the targeted formations displayed a wide range of pore pressure and different formation stability from well to well. Therefore, mud systems that were much heavier than pore pressure ECD had been used to drill the reservoir formation in past operations. The concern of the operator was that by doing that the reservoir could be damaged to a point that true characteristic of the reservoir could be disguised, or even worse, the reservoir was hidden.

The primary objective of this well is to characterize Formation A and Formation C and evaluate gas production while drilling. UBD/MPD technology was adopted to achieve the planned objective. One of the major benefits of UBD/MPD technology over conventional drilling technology is that UBD/MPD technology has the capability of a prompt and effciant response to the downhole conditions as they occur by simply adjusting the back pressure. This is critical on an operation like this with uncertain formation characteristics, such as pore pressure and hole stability issues.

This paper describes the planning and implementation of the UBD/MPD technique in the 8 3/8” and 5 7/8” section hole of this well and reviews the results of the drilling operations.
Successful Deployment of Multistage Fracturing Systems in Multilayered Tight Gas Carbonate Formations in Saudi Arabia
Authors: Hussein Al-Jubran Hasan , Wilson Stuart , Johnston Bryan
Published: January 2010

Horizontal wellbores have enabled significant increases in productive zone contact areas. However, even with these increased contact areas, the expected long-term production increases were not initially realized with conventional stimulation techniques. Multistage fracturing systems have resulted in impressive long-term production improvements, but the deployment of these assemblies into deep and long reach horizontal wells was initially problematic. After the original difficulties were encountered, modifications were made to the well preparation and assembly running procedures which resulted in the recent successful deployment of several multistage fracturing systems into long reach horizontal wells in the Khuff formation in Saudi Arabia.

This paper will discuss several factors impacting deployment in these conditions including:

Construction of the wellbore Deploying through multiple layers with varying reservoir pressures Preparation of the wellbore Running in hole techniques and procedures

With the implementation of these well preparation and deployment techniques, several multistage fracturing assemblies have been successfully installed allowing proper placement of multiple fracturing jobs, which have in turn resulted in continued production improvements from tight gas formations.
Deep Sour Gas Reservoir Development and Challenges
Authors: Abed A.. , El Gohary M.. , Abu Snaineh A.. , Guettat M.. , Ahmad M.. , Lozano J.. , Al Reyami M..
Published: January 2010

An Offshore Gas Field discovered in early 70’ is a large anticlinal structure located in the shallow marine waters west of Abu Dhabi island. The area is considered by UNESCO as Biosphere reserve and is protected. Several development options have been studied to develop the gas reserves from existing Artificial Island with a minimum impact to the environment.

Geological and reservoir simulation compositional models have been prepared to optimize the development plan, identify the minimum number of wells, target rates in order to maximize the gas recovery and sustain the gas plateau rate as long as possible. Building these models was a challenge due to the lack of 3D seismic data and the limited production data from the appraisal well. Due to the sensitivity of the area, the main challenges of the project implementation are the impact on the environment during drilling phase and the facilities construction and its operation.

The required refurbishment of the existing island and access channel to the island was a concern that was studied. Drilling of 10 to 12 closely clustered directional deviated gas wells from one existing artificial island in the centre of the field into a High Pressure and High Temperature, high H2S (14-24%) and deep reservoirs environment is also a big challenge. To effectively drain the entire reservoir from the island, the rigs should be capable to drill more than 25,000 ft extended reach deviated wells.

Reducing the impact on this sensitive environment was the major concern; hence an HSEA study has been carried out to develop the mitigation plans. The possibility of drilling using more than one rig simultaneously on the island to deliver gas on time has been studied to minimize the duration of the drilling operation and associated risks. Special completion materials for these extreme environments were also studied. Material selection for different well types/conditions has been carried out.
Optimized Practices Followed in Testing & Completion of Deep Jurassic Exploratory Wells of KOC
Authors: Packirisamy S.. , Al-Bader Haifa , Singh J.R.. R. , Al-Bader Hamad Esam
Published: January 2010

KOC management has created an experienced team to test and complete new Jurassic wells drilled in North Kuwait field. Testing & completion has been a challenging task in handling Jurassic reservoirs because of deep wells, HPHT conditions, heavey mud weights and sour volatile oil/gas condensate. All wells were tested either with Polished Bore Receptacle (PBR) or retrivable/permanent packer designed to achieve the objectives. New Jurassic discovery wells were also tested on long term basis using Early Production Facility (EPF) in order to conclude, evaluate and confirm the overall potential of Jurassic formation for further production enhancement and delineation/ development work.

This team has developed optimized practices based on the experiences gained in testing and completion of more than 20 exploratory/delination wells drilled in Jurassic reservoirs. These optimized practices have been applied in several deep/HPHT wells drilled in Kuwait and tested safely & economically. It illustrates a very valuable experience of KOC's exploration process in deep well testing & completion.

This paper describes practices followed, problems faced and remedial actions while testing & completion of deep/HPHT Jurassic wells. Details of procedure developed, techniques applied in perforating, activation, stimulation, fracturing, short-term/long term testing is also presented in this paper.
Proppant Fracturing for Ultra-High Pressure Deep Gas Reservoir
Authors: Wang Yonghui , Zhang Fuxiang , Cheng Xingsheng , Peng Jianxin , Li Yongping
Published: January 2010

A successful case of proppant fracturing on an ultra-high pressure (Pressure gradient 0.018MPa/m), deep (5725-5783m) sandstone gas reservoir in Western China is described in this paper. Several technologies including high density(density1.12g/cm3) frac-fluid, high density(density 1.25g/cm3) flush-fluid, proppant slug, multi-step slurry injection schedule, real time analysis were used. 20-40 mesh 28.5m3 proppant was injected into the payzone successfully. The result is encouraging. The production reach to 307,000m3/d after the treatment. The project is a technical and economical success. The lessons acquired in the well will be a reference for the following similar wells.
Implementing Smart Solution for Controlling Water Cut in South Pars Gas Field from Environmental Point of View
Authors: Rahimi R.. , Tahami A..
Published: January 2010

In the current decade as the result of increasing volume of waste all over the world, the effect of discharging produced water on the environment has lately signified and became an environmental concern. Therefore controlling excessive water production is one of the challenges in mature and declining oil and gas fields. Nowadays, statistics show that ratio of produced water to oil is 3 to1, and thus the largest waste stream generated in oil and gas industries, is produced water. It is a mixture of different organic and inorganic compounds especially polycyclic aromatic hydrocarbons (PAH) that has detrimental destructive effects on marine environment.

Recently water management becomes ever more important as more green fields changes to brown fields in the struggle to supply a world hungry for hydrocarbon. So improved water management practices are being implemented worldwide to maximize well productivity and reduce destructive effect of produced water discharge. Because of this environmental awareness, recently stringent regulations have established on discharge of produced water. Various methods such as drilling horizontal wells, water shut-off jobs and using smart devices have different degrees of success in decreasing water production. A smart well is the one with downhole instrumentation installed on the production tubing.

Using smart well technology in Middle East fields in order to control water production had been experienced and it had considerable outcome especially in multilateral wells. Based on strategic importance of South Pars as the greatest gas field in the world and the probability of increasing its water cut especially from deep gas layers in near future, feasibility study of implementing smart solution in south pars gas field has been surveyed. Here in this paper environmental harmful impact of produced water from this field and application of smart well technology for water cut reduction has been investigated.
Jurassic Tight Carbonate Gas Fields of North Kuwait: Exploration to Early Development
Authors: Al-Eidan A. J. , Narahari S. R. , Al-Awadi M.. , Al-Ajmi N. H. , Pattnaik C.. , Al-Ateeqi K.. , Al-Houli M. M. , Kidambi Vijaya Kumar , Keyser T. De
Published: January 2010

Exploration activity during the last eight years, targeting Jurassic carbonate reservoirs in North Kuwait, has culminated in the discovery of six major tight gas fields, encompassing an area of about 1,800 sq km with a reservoir gross thickness of about 2,200 ft. These fields are the first free-gas fields in Kuwait, which were put on early production during 2008. The reservoirs are characterized by dual porosity, dominated by low porosity and permeability, in deep HP/HT conditions, with wide variety of hydrocarbon fluids ranging from black oil to gas condensate with sour gas. Typical per well production rates are up to 5,000 BOPD/BCPD and 10 MMSCFPD, making them an excellent commercial success.

Despite the limited number of 38 well penetrations to date in this large Jurassic complex, understanding of the depositional model has improved over time through careful integration and detailed interpretation of log, core, and seismic data. Based on these studies, a depositional model incorporating sabkha, tidal flats, lagoon, backshoal, shoal, shoreface inner shelf, outer shelf, and slope/basin depositional environments has been built. Hypersaline brines were generated in the lagoon and seeped downward, selectively dolomitizing the underlying strata, creating secondary porosity and permeability, and significantly improving the reservoir characteristics in some of these fields. From the early phases of exploration, the role of natural fractures in enhancing the production from these reservoirs was recognized. Accordingly, well data acquisition is designed to maximize reservoir understanding. Delineation and development well placement are optimized to penetrate the most heavily fractured corridors, through a combination of seismic attributes and Discrete Fracture Network modeling, constrained by available well data.
Understanding Fractures Through Seismic Data: North Kuwait Case Study
Authors: Narhari Srinivasa Rao , Al-Kandari Abdul Latif , Kidambi Vijaya Kumar , Al-Ashwak Samar , Al-Qadeeri Bashar , Pattnaik Chinmaya
Published: January 2010

Understanding fracture corridors is the primary driver for successful development of fractured carbonate reservoirs. This assumes further significance if the carbonate reservoir is characterized by very low porosity and permeability; producibility of the reservoir is purely dependent on the presence of natural fractures. Distribution and type of natural fractures is a function of palaeo & present day stress, structural elements, regional tectonics and diagenetic history. Direct detection of fractures is below the resolution of conventional seismic data. However, through a combination of seismic derived attributes integrated with well data, it is possible to better understand the distribution of fracture swarms.

Kuwait Oil Company (KOC) is currently engaged in an early phase of development of a tight fractured carbonate North Kuwait Jurassic gas play. Considering the limited well control, field development is heavily reliant on seismic data for fracture characterization. This paper presents our current understanding of the relationship between fractures observed in the well data and structures, faults and lineaments interpreted on seismic data. In addition to conventional seismic analysis a suite of seismic attributes including Dip, Coherence, Edge and 3D Volume curvature were used for mapping structures, faults and minor lineaments. Well-wise and field-wise analysis of relationships between seismic derived attribute-pattern and fracture orientation was established. The understanding between these two different sets of data has helped in locating potential zones of sweet spots for placing successful delineation and development wells. These seismic attribute volumes were also used as soft constraint for building the Discrete Fracture Network (DFN) model for populating the fracture network in the reservoir model. The data presented in this paper are from the Raudhatain, Sabriyah and North West Raudhatain (NWRA) fields for the Najmah-Sarjelu part of the Jurassic section.
A New Exploration Play for Saudi Arabia, the Rhuddanian Sandstone
Authors: Hayton S.. , Heine C. J. , Sherba E. E. , Gratto B.. , Shenggen Z.. , Shicheng W..
Published: January 2010

Recent exploration activity by Sino Saudi Gas Ltd (SSG, a joint venture between Sinopec and Saudi Aramco) in southern Rub'al-Khali has resulted in the identification of a Rhuddanian-aged sandstone directly above the Base Qusaiba Hot Shale and interbedded with the cooler shales. While not as extensive and prominent as the well known mid-Qusaiba Sandstone, this lower sandstone has great potential as a hydrocarbon reservoir given its location directly above and interbedded within one Saudi Arabia's principal source rocks.

A sudden unexpected increase in mud gas and sandstone cuttings while drilling the Qusaiba shale in an SSG exploration well, led SSG to cut a 30 ft conventional core. The core contained interbedded sandstone and shale. FMI logs also clearly showed interbedded sandstone and shales, which allowed the very precise location (to within less than 3″) of rotary sidewall cores to complement the conventional core. Analysis of the conventional cores indicates that the sandstones were deposited by mass-flow mechanisms, including turbidity flows. The depositional system is interpreted as the lateral edges of a basin floor fan.

While routine porosity and permeability analysis of the conventional core plugs and rotary SWCs indicates that the Rhuddanian Sands are a very low permeability reservoir at this location, it did flow hydrocarbons on a cased hole test.
Tight Gas Exploration in Saudi Arabia
Authors: Hayton S.. , Heine C. J. , Gratto B..
Published: January 2010

Saudi Arabia, long known for its enormous structures, very high rate and relatively shallow wells is continuing its extensive conventional exploration activity. It is also looking at "unconventional?? resources, especially tight gas reservoirs.

The primary focus of the tight gas effort within Saudi Aramco has been in trying to understand the hydrocarbon resources, reservoired in the lower Paleozoic siliciclastic succession. This succession is dominantly a pile of sandstones, several thousand feet thick. In the middle is the Silurian aged Qusaiba Shale. The nature of the Lower Paleozoic succession varies considerably across Saudi Arabia, from outcrops to 20,000 ft+ depths, and with reservoir qualities that range from conventional to distinctly tight.

Exploration activity in Southern Saudi Arabia over the past four years has more than doubled the number of lower Paleozoic penetrations in the South Ghawar and Rub'al-Khali areas. This activity has resulted in a number of key developments including: Confirmation that the pre-Qusaiba sandstones of the Sarah and Qasim (Late Ordovician) contain significant untapped tight gas resources.Identification of entirely new play concepts in Saudi Arabia, some of which are discussed in this paper.Increased understanding of the complexity and opportunities of the Lower Paleozoic succession in Southern Saudi Arabia.

Current conventional exploration activity in Northwest Saudi Arabia is acquiring additional data to allow the known tight gas resource in the region to be better quantified. Due to the shallower depths of the tight gas resource and local demand for gas, Northwest Saudi Arabia is seen as the one of the priority areas for Saudi Aramco's tight gas efforts.

Saudi Aramco sees the potential of using local tight gas resources in conjunction with conventional resources to underpin regional development. Saudi Aramco has thus initiated activities that will enable it to commercialize these resources for the benefit of the Kingdom.
Doubling the Middle East's largest HPHT Rig Fleet – Case History of the Start-up of Six New 3000 HP Rigs in Kuwait
Authors: Al-Saeedi M. J. , Al-Fayez F. A. , Al-Enezi D.. , Al-Mudhaf M. N. , McKinnell D. C.
Published: January 2010

Kuwait may be one of the Middle East's smaller countries, but it has one of the largest programs of deep well drilling in the region. This is due in part, to a unique geology where the presence of a deep salt section at the beginning of the Jurassic age sequence has resulted in a series of highly pressured reservoirs and formations below.

Exploration drilling has focused on deep HPHT wells to search for high quality oil and gas from these Jurassic and Triassic/Permian formations. The rigs employed have high technical specifications (3,000 HP/15K BOP), which are under constant evolution to meet new challenges and to deliver improvements in performance and safety.

In 2007, Kuwait Oil Company launched the ‘North Kuwait Gas Development Project’ to fast track production of gas/light oil from Jurassic horizons in six northern oilfields. This project, plus increased demand for exploration and development wells in other areas made it necessary to double the existing fleet of deep rigs from six to twelve, over a very short time duration.

The new rig contracting process commenced with a review of present rig equipment specifications. An analysis of the operational benefits/shortcomings of the new concepts and technology features fitted on current KOC rigs was carried out. Lessons learnt were applied to the new specifications in order to develop rigs with a high safety potential, optimum level of automation and ‘state-of-the-art’ equipment.

Details of challenges faced during rig construction, mobilization and commissioning have been analyzed, including rig market conditions and those related to the securing of experienced manpower for efficient rig start-up.

This paper will discuss all aspects connected with specification, construction, delivery and start-up of the six new rigs. This case study will also focus on lessons learnt and conclude with recommendations on improvements for future new rig start-ups.
Optimizing Microemulsion/Surfactant Packages for Shale and Tight-Gas Reservoirs
Authors: Rickman R.D.. D. , Jaripatke Omkar
Published: January 2010

Success of the stimulation treatments in low-permeability, gas-producing formations largely depends on the fracture-face damage mitigation and cleanup of stimulation fluids from the propped fracture and formation matrix. These factors become even more critical in deep, conventional gas reservoirs, unconventional coalbed-methane reservoirs, shale, and ultralow-permeability tight-gas sands. Traditionally, in the industry, the focus for the success of the stimulation-fluid cleanup had been placed on conductivity damage of the proppant pack. It has more recently been realized that gas recovery and post-fracturing treatment results can be strongly dependent on other factors like wettability issues, phase trappings, water/gas relative permeability, and saturation states. The efficiency with which the fluids get extruded from the matrix or from the hydraulic fractures to the wellbore gets greatly diminished if conventional stimulation fluids are used without appropriate surfactant systems, leading to longer ROI times. Many microemulsion-surfactant systems have and are currently being developed based on the study of factors affecting the dynamic-displacement behavior through the application of surfactants. Many so-called optimized treatments are not designed to adequately deal with all the issues within a particular well or reservoir and might actually create or cause more damage than originally existed.

This paper describes laboratory test methods, comparisons, and results used for evaluating and selecting surfactants for deep, gas-bearing formations, such as shales and tight sandstones. Data presented here will aid operators in choosing the best surfactant/microemulsion package for optimizing hydrocarbon production.
Three Different Methods of Mapping the Characteristics of Induced Fractures Related to Both Hydraulic Frac and Production as Measured With Microseismic Array Technology from Observation Wells, Treatment Wells and in a Permanent Setting
Authors: Brooks Nicholas , Gaston Graham , Rangel Jaime
Published: January 2010

Passively listening to induced fracturing that is related to production or hydraulic stimulation from a downhole setting has become widely accepted in the oil and gas business. Completions planning and infill drilling programs continue to benefit from this technology with the ultimate goal of enhancing recovery whilst reducing overall costs. The mapped microseismic events are driven by localized and regional stress directions and pre-existing fracture networks. The microseismic map influences the subsequent interpreted fracture network. Reservoir performance and hydrocarbon recovery can be optimized by correctly applying the right downhole monitoring technology to a given specific objective. Here we present three different methods for collecting microseismic data from a downhole environment. We demonstrate the variable response of a single reservoir to hydraulic fracture treatment. Standard observation well setup and treatment well deployments are discussed and case histories are shown. We weigh up the benefits and drawbacks of both. With the advanced observation well tool we show better lateral coverage with high variability of formation response. The tool that can be deployed in the treatment well itself shows better accuracy of frac height measurements and highly localized changes in frac orientation but with limitation of lateral coverage. Extending the monitoring window to years or decades requires yet a different approach. The unique system that contains no downhole electronics extends the life expectancy of the monitoring array for true permanent applications. The three distinct techniques of observation well deployment, treatment well deployment and permanent deployment are successfully applied and demonstrated with case studies. The data that is collected can be used for planning and optimization in the short, medium and long term. When applied in difficult and unconventional settings, this leads to increased reservoir performance and reduced overall cost.
Discrete Element Simulation of Induced Damaged Zones in Perforation of Deep Gas Reservoirs
Authors: Asadi M. S. , Sarmadivaleh M.. , Nabipour A.. , Sabogal J.. , Rasouli V..
Published: January 2010

Perforation job consists of creating holes in the near-wellbore formation by shooting the perforation agent through the formation in order to establish fluid communication between the wellbore and hydrocarbon reservoir. During this process, some degree of damage occurs in the rock surrounding the perforated tunnel. Determining perforation-induced damage to the reservoir rock and its ultimate impact on the well productivity is of particular interest to the industry.

A discrete element-based numerical simulator was employed in this work to evaluate stress redistribution and failure zones around a perforation tunnel in a 2D plane. Formation was simulated as an assembly of densely packed particles bonded together. Macro-mechanical properties of the rock were estimated by changing the micro-parameters in several simulated biaxial tests. The perforation was simulated by shooting an external body penetrating through the wellbore wall in a high velocity, which generates the perforation tunnel as a result of the particle bonds being broken. Shear and tensile failures are expected to develop around the perforation tunnel.

The extent of the damaged zone (EDZ) and the depth of penetration (DOP) in a perforation job are important parameters which are influenced by formation mechanical properties, in-situ stress magnitude and direction and the perforation agent size and velocity. In this paper the effect of these parameters are studied by conducting number of sensitivity analyses. The results indicated that the EDZ reduces as formation strength increases and this effect is lesser if formation is perforated at maximum horizontal stress direction. Also, it was seen that both EDZ and DOP reduce as formation grain size increases. Larger perforation agents resulted in a lesser DOP but wider EDZ.
Thermomagnetic Analyses of the Permeability Controlling Minerals in Red and White Sandstones in Deep Tight Gas Reservoirs: Implications for Downhole Measurements
Authors: Ali Arfan , Potter David K.
Published: January 2010

Our recent work on deep tight gas reservoirs containing red and white sandstones (Potter et al., 2009) has shown that the presence of small amounts of hematite in reservoir samples has a dramatic effect on permeability. Such conclusions were made using laboratory based low and high field magnetic susceptibility measurements on reservoir rock samples and by comparing these measurements with the permeability data. These rapid, non-destructive magnetic measurements have previously been applied in clastic reservoir samples (Potter, 2005, 2007; Ivakhnenko, 2006; Ivakhnenko and Potter, 2006, 2008; Potter and Ivakhnenko 2007, 2008) and carbonate reservoir samples (AlGhamdi, 2006; Potter et al 2008). However, such laboratory based analyses are not representative of the downhole in-situ conditions, especially in deep gas reservoirs where temperature can reach quite high values. Typical tight gas reservoir depths can reach to about 4000m (Abu-Shanab et al 2005) and 6000m (Jianming et al 2008) and the equivalent temperatures would measure 131 °C and 192 °C respectively (Mayer-Gurr, 1976).

This paper investigates the in-situ magnetic properties of permeability controlling reservoir minerals (hematite and illite in this case) via laboratory experiments to model downhole conditions. We perform magnetic hysteresis measurements at various temperatures in order to 1) quantify mineralogy and 2) to show changes in the magnetic behaviour of these minerals at in-situ downhole conditions. From these measurements, we are able to show whether the mineralogy and/or domain state of these permeability controlling minerals is likely to change with temperature in the deep gas reservoirs. This can have a major impact on permeability.

We also show some results from another red and white tight gas reservoir where there is a strong correlation between core permeability and magnetic susceptibility data. In this particular reservoir, the presence of siderite in the white sections of the core greatly improves permeability. Once again for this reservoir, the permeability is low in red sections of the core due to the presence of hematite.
How to Define a New Higher Strength Drill Pipe for Maximizing Safety
Authors: Sévignon Anne , El Bachiri Kamal , Gateaud Arnaud , Flores Vincent , Marchebois Hervé
Published: January 2010

The evolution of drilling programs has driven the industry to develop more suitable solutions adapted to extreme and aggressive conditions such as Sour Service environments. High strength drill pipe is necessary to achieve these deeper drilling targets because Sulfide Stress Cracking susceptibility is observed even in minimal concentrations of H2S partial pressure.

Due to the astringency of the sour environment, particular precautions have to be defined to select and characterize an adapted Sour Service steel grade. Controlling crucial manufacturing parameters is the key to successfully supplying products for these critical applications. Steel microstructure, chemical composition, cleanliness and heat treatment process control are all important to promote Sulfide Stress Cracking resistance in high strength drill pipe. Moreover, controlled yield strength, restricted hardness and improved fracture toughness are the mechanical parameters enhancing the ability of these drilling products to be used safely and efficiently by drilling contractors and operators in aggressive wells.

This paper presents the latest VAM Drilling solutions in terms of steel chemistries and manufacturing process controls highlighting key parameters that drilling engineers and specifiers should consider when planning sour gas wells. The paper also introduces further developments to be sought for deep and Extended Reach Drilling above current material limits.
Rock Physical Properties Computed from Digital Core and Cuttings with Applications to Deep Gas Exploration and Development
Authors: Li Guoping , Diaz Elizabeth , Nur Amos
Published: January 2010

Digital rock physics involves high-resolution imaging of rocks, creation of 3D digital (or virtual) rocks, and sophisticated rock property computations. The state-of-the-art CT scanners currently in use allow complicated reservoir rocks to be imaged at resolutions ranging from +50 microns (μm) to a few nano-meters, suitable for analyzing conventional as well as unconventional rocks like tight sandstones, carbonates and shales. Precise separation and capture of the actual pore space in a rock and its solid matrix enables numerical simulations of multi-phase fluid flows within the pores, and makes possible fast and accurate computations of essential rock properties. Key reservoir parameters, such as porosity, absolute and relative permeability, can be computed within a few hours up to a couple of weeks.

Unlike traditional physical measurements, digital imaging-based computational rock physics is not constrained by the shape and size of rock samples under investigation, and therefore can be applied to while-drilling cuttings analysis, an important consideration for expensive deep gas drilling.

Such technologies are particularly suitable for complex reservoir characterization and resource assessment for unconventional tight gas sand and/or shale exploration and exploitation, for this type of reservoirs often, if not always, exhibit extreme heterogeneities in flow characteristics.

Some examples of practical applications include but are not limited to: detailed pore geometry (pore size, connectivity and distributions) study, deterministic volumetric appraisal for ultimate gas resources and risk assessment, flow simulations at pore scales, drill cuttings rock physics (strength, Young's modulus, porosity-permeability profiling) to guide vertical and horizontal well stimulation engineering, effects of clay, minerals and diagenetic processes, partial water saturation, and fracture network characterization.

In this paper, the concepts and procedure of digital rock physics will be fully introduced. In addition, we will present some case studies from unconventional plays to demonstrate its applicability.
Field Application of Applying the Best Practice in Proppant Fracturing Shaly Sand Formation
Authors: Johnson Dan , Zaki Said , Mendez Alfredo , Kuchinski Robert , Amer Mostafa Amin
Published: January 2010

This paper describes a field example of Planning to frac tight Shaly sand formation which offers a unique challenge for fluids, equipment and personnel. The main objective is to maximize the value of the field over its productive lifetime. The primary benefit from these applications is the utilization of the equipment capabilities and the fluids properties to get the best possible fracture length and conductivity for optimizing field-development economics.

The objective of the paper is to make available the information needed to do the proper preparation and execution for similar well conditions in the area. Starting with the proper field study to have the best candidate for the hydraulic fracturing was a key parameter for the success of the job. This field has started with initial pressure of 2400 psi and total potential of 7000 BOPD. Other consideration concerning the lithology characteristic of the reservoir, the tight shaly sand formation will not produce at its best potential without the high pressure proppant frac. The selection of the fluid suitable for this job was mainly to have to best properties and stable fluid to carry the proppant, not damaging to the formation, not to cause any clay swelling, easy to X-Link and easy to break after the job. Also the selection of the equipments to give the proper rate and pressure with fully remote control from the data van was considered to have a successful job.
Mechanical Earth Modeling Improves Drilling Efficiency and Reduces Non-Productive Time (NPT)
Authors: Moazzeni Alireza , Nabaei Mohammad , Shahbazi Khalil , Shadravan Arash
Published: January 2010

As time goes by, increase in world energy demand forced oil and gas companies to drill deeper in order to produce more oil and gas for quenching the thirst of human needs. This requires drilling layers with various lithologies with variable characteristics and dealing with more drilling problems as going deeper. Mechanical Earth Model (MEM) should be developed to bypass drilling problems. This model will be used for analyzing instability of the wellbore wall, selecting optimized azimuth and inclination for well trajectory, optimized perforation, sand production analysis and stimulation operation design. In this paper, a mechanical earth model is developed for one of the Iranian fields in Middle East and then drilling data are employed to optimize well trajectory based on wellbore stability models and higher penetration rate. Theoretical results show remarkable increase in drilling performance and applying optimized parameters will shorten drilling operation.
Uncertainty Analysis in Unconfined Rock Compressive Strength Prediction
Authors: Nabaei Mohammad , Shahbazi Khalil , Shadravan Arash
Published: January 2010

Lots of sources can be used to derive unconfined rock compressive strength (UCS) along the wellbore as a key input of failure criteria for wellbore stability analysis. Laboratory tests are the most accurate methods to obtain rock strength which mainly are destructive and result in a set of discrete data. On the other hand, non-destructive methods (log based approaches), deliver a continuous rock strength log, however, the accuracy of these techniques is still dubious and they should be calibrated with lab data. If the evaluated rock strength contains some errors, final mud weight window will be affected by these errors which lead to inaccurate mud weight selection for safe drilling operation and consequently increase in total well cost. Whole data in UCS log shall be multiplied or added by a number to match laboratory results. This calibration approach may superficially show good match between results from log and laboratory, though all data may not represent real UCS and show same uncertainty. In this paper, a modified calibration approach based on lithology, compaction, fluid content and porosity is proposed for calibration of UCS logs. Performed cross validation results show a good match between laboratory data and modified UCS profile.
The Role of Resistivity Image Logs in Deep Natural Gas Reservoirs
Authors: Kalathingal Paul , Kuchinski Robert
Published: January 2010

Occurrences of deep gas are commonly found in clastic reservoir rocks. The great depths of these reservoir rocks often result in rocks with low porosity and poor permeability. In order for these reservoirs to be productive, natural fracture systems or induced fractures from stimulation processes are required to allow gas to flow to the well bore. In order to assess the potential of these reservoirs, explorationists around the world depend on data acquired from resistivity imaging tools to visualize the fractures.

This paper will discuss fracture analysis using resistivity image data that provides better reservoir characterization on fractured reservoir than the normal open hole logs. Image data has higher resolution compared to the basic open hole data, and allows for fracture visualization down to 2mm. Petrophysical analysis using basic open hole data will average out the fine details of the fracture and its effects on porosity and permeability. Image based petrophysics known as “Image petrophysics” allows for the conversion of high resolution image data to high resolution petrophysical properties which provides greater understanding of the impact of the fractures on reservoir characterization. The use of Image data calibrated with either core data or basic open hole data allows for the derivation of high resolution porosity distribution. Permeability derivation can also be achieved using image data calibrated with core data. This process can also be extrapolated to wells that are un-cored.

This paper will also discuss the challenges of acquiring image data from these deep environments by employing memory based image tools that can be conveyed using a broad range of conveyance techniques.
A Systematic Approach to the Integration of Upper and Lower Completions: A Strategy for Deep Gas Applications
Authors: Jones Richard
Published: January 2010

In designing completions for deep, high-temperature applications, operators have historically concentrated their efforts on two sections, either the upper or lower completion. By focusing solely on the two sections, operators have been unable to maximize the compatibility of the entire well completion. An organized, well-planned, incremental approach to the two components of the well completion leads to safer, more efficient installations and long-term operability. This paper will discuss the challenges associated with deep gas completions and how a systematic approach to overall completion design can save time and money while establishing a safe installation process. In addition, it will cover the emerging technologies in the completions field for the deep gas marketplace and how they can improve completion design effectiveness.