Tight gas fracturing was pioneered in North America in the 1970's and 1980's, and also has a relatively long history in Germany. In the rest of the world, however, massive fracturing for production from tight gas formations (i.e. k < 0.1 mD) has been very rare, due mainly to poor economics, rather than lack of opportunities. A massive oil field was recently discovered in Rajasthan (northwest India). The field development would require significant amounts of natural gas for heating and processing of the waxy oil to be produced. The most economical solution to provide sufficient gas in this remote desert location was to produce it from a deeper formation discovered in the same area. The majority of the gas is contained in a volcanic section of basalts and felsics. A fracturing campaign was performed in 2006 on three deep gas wells to evaluate the post-stimulation production increase from a number of different horizons, with base formation permeabilities varying from 0.005 to 0.15 mD. A comprehensive program of core testing, fluids compatibility testing and pre-fracture diagnostic injections was performed. Fracture stimulation treatments were performed in three different sections of this very thick gas-bearing formation (> 400 m gross height). The formations ranged from the highest permeability (0.15 mD) Fatehgarh sandstones, to a lower permeability Felsic section (0.05 mD) and the lowest permeability volcanic rock (0.005 mD). All three types of rock were stimulated successfully and post-fracture well testing showed initial production rates agreeing with what was expected based on reservoir simulation. This important result supports the proposition that unconventional gas resources in Asian countries can be attractive when stimulation techniques perfected in other areas (i.e. North America) are applied 1. Introduction The Raageshwari Deep gas field was discovered by RJ-E-1 (Raageshwari-1) in 2003. It was the second well drilled on the Central Basin High (CBH), a 40km-long composite feature of elevated N-S-oriented fault terraces, arranged in echelon within the Southern Barmer Basin of Rajasthan (Figure 1). The Central Basin High (CBH) structure is divided into many major horst blocks, of which Raageshwari is the shallowest. Raageshwari Deep is a tight lean gas condensate field and is contained in an arrowhead-shaped horst block formed at the confluence of three fault trends and contains 4 reservoir bodies (Fatehgarh, Basalt, Felsic and Sub-Felsic).

Summary Most existing production of waxy oils occurs in high-permeability formations, and wax issues are mostly a problem in the production tubing or pipeline. Large reserves also exist in low-permeability formations that require hydraulic fracturing for economic production. Such a reservoir was recently discovered in Rajasthan, northwest India, overlying a more typical high-permeability formation, both with high-pour-point waxy oil. Because a very large amount of oil in place is present in the low-permeability formation, two fracturing campaigns were performed in two different horizons to assess the potential for successful well stimulation. The first fracturing campaign (on four wells) showed limited success. A study was performed to determine the reason for the failure, and significant changes were made for the second campaign. This paper documents the second campaign. This campaign featured the first successful use in India of heated fluids to stimulate a shallow, low-permeability, massive oil reservoir containing high-pour-point waxy oil. Introduction Numerous exploration and appraisal wells have been drilled in the RJ-ON-90/1 Block in Rajasthan, northwest India, targeting primarily the prolific Fategarh reservoir (Zittel et al. 2008). Many of these wells have encountered hydrocarbon-bearing-potential reservoir-quality rock in the shallower Barmer Hill formation. Fig. 1 shows the field locale, which is situated just east of the border with Pakistan. The Barmer Hill formation is a shallow (700 to 800 mTVDSS), rich to very-rich source rock and has been described generally as siltstone and claystone, with gas peaks and frequent oil shows. Because the source rock is lacustrine in origin, it has generated waxy oil. Fluid analysis from the Barmer Hill reservoir shows high pour points (>45°C), wax appearance temperature (WAT) several °C less than reservoir temperature (˜70°C), and in-situ viscosities of tens of centipoises. The in-place hydrocarbon may be large, especially in the north of the basin because of the Barmer Hill's high porosities (25-30%). Producing these hydrocarbons, however, is not easy. Natural-flow openhole tests in three separate wells in the northern fields showed mixed-to-poor results and very low permeability (1-10 md), as estimated from slug-flow-well test analysis. To prove the commercial potential of the Barmer Hill reservoir, a hydraulic-fracturing campaign was conducted.

The Solan oil field is located offshore in the hostile north Atlantic ~135 kilometres west of the Shetland Isles, UK, in ~135 metre water depth. The field commenced production in 2016. The relatively remote field was developed by four subsea wells tied back to a single slim jacket with a minimum facility topsides. The development includes several innovative features such as full automation, which enables full remote control from an onshore control room in Aberdeen, UK, but strikingly, a world development first involving the installation of an independent steel subsea oil storage tank (SOST) located ~300 metres from the platform. The concept selection, design, fabrication, installation and operation of this novel feature are the subject of this paper. The concept selection of the SOST was driven by several factors including HSE, life cycle cost and operational considerations for this modest sized development in a harsh marine setting. An obvious competitor concept is a subsea well and FPSO alternate; the pros and cons of each approach are compared, using actual field performance now seen versus assumption at the time of concept select. The multiple-compartment SOST is capable of holding almost 300,000 barrels of stabilised oil; it has an in-air weight of ~10,100 tonnes and internal dimensions of 45m x 45m x 25m. The oil is offloaded to a shuttle tanker through a single anchor loading (SAL™) system with the offloading hose stored on the seabed, which is picked up using a pennant line. Oil export to the tanker is driven by hydrostatic displacement by treated seawater from the topsides. This operation is conducted while still producing oil to the SOST. The tank design has novel features for installation, oil-water interface management and corrosion monitoring and subsea inspection. The tank's detailed design and construction phase involved some significant changes as the structural and fatigue life issues were fully analysed and implemented. The installation required significant pre-planning with the use of a very large lifting sling arrangement and a smart air venting and water ballasting system, to then land its eight skirt piles to a tight tolerance on the seabed. Following a commissioning program and trial tanker offload using treated seawater alone, over the past year the SOST has now successfully undergone numerous oil fill and tanker offload operations. There have been learnings regarding the offloading operation but to date the concept has worked in a manner very close to expectation with a full tank offload achieved in less than ~36 hours. The paper closes with a review of how the concept could be improved further considering the experiences now gained from both the project and operational phases.

The Mangala, Bhagyam and Aishwariya Fields were discovered in early 2004 in the northern Barmer Basin of Rajasthan, in northwestern India. The data acquired in the field wells (including almost two kilometers of core) enabled a precise estimation of field stock tank oil initially in place (STOIIP). This paper summarizes the techniques that allowed the estimate of STOIIP to be more precisely defined and to be revised upward by 12%, a substantial increase when dealing with a billion barrel field (Mangala Field). Initial evaluation of the log data indicated a sequence of clean, quartzose sandstones with porosity greater than 25%. High porosities together with resistivity in the oil column over 5,000ohm-m, suggested that water saturations (Sw) were ~15% or even less. Based on the initial data and conventional techniques, the initial STOIIP estimates were made for the three fields. An extensive core analysis programme was begun in appraisal wells, with the objective of improved definition of the actual reservoir STOIIP's. Two appraisal wells were cored with synthetic oil based mud, and Dean-Stark Sw analyses were done. In addition to routine core analyses and the Dean-Stark Sw data, a sizeable set of other special core analyses is also available. This includes extensive capillary pressure data, laboratory NMR, and core electrical properties measurements. The petrophysical dataset verifies the existence of Sw's that are typically less than 5%PV, and often near 1%PV, in a very high-permeability and high-porosity reservoir containing little clay. The reservoir contains a medium gravity, highly paraffinic oil, and is moderately oil-wet. The various laboratory datasets challenged some of the traditional assumptions concerning the use of Archie constants in such reservoirs for Sw calculations. The upward revision of STOIIP is significant, and can be principally attributed to the more accurate estimation of reservoir fluid saturations. As this work demonstrates that very low Sw values exist in the Barmer Basin, the Mangala, Bhagyam and Aishwariya fields can provide a model for the appropriate economic evaluation of similar reservoirs. The laboratory results challenge some of the traditional thinking about the petrophysical properties of reservoirs such as these. It is indeed possible, that high quality reservoirs can have initial water saturations lower than 5% of pore volume on average, and with some zones less than 1%. Conventional log tools and analysis methods will not reveal these low levels without integration with core data and appropriately designed core analysis programmes. Also, and perhaps more importantly, this work clearly demonstrates the economic worth of extensive laboratory measurements and analyses on high-volume, high-value reservoirs such as those of the Mangala, Bhagyam and Aishwariya Fields. Introduction The Mangala, Bhagyam and Aishwariya Fields ("MBA" Fields) were discovered in January 2004 (Yashwant, et al, 2006) by targeting a series of simple, tilted fault-block traps formed within the rifted, Tertiary Barmer Basin (Figure-1).

The unitised deepwater Jubilee Field is located 60 km offshore Ghana andcommenced production in late 2010. An FPSO has been installed with oil capacityof 120,000 barrels per day. This was a major oil project execution carried outin a country new to such activities. It was clear from the time of discoverythat expectations in Ghana regarding a positive impact being made by theproject would be high. In the initial project phase of just over 2 years, the Unit Operator (UO) wasresponsible for carrying out the in-country activities, including build of theorganisation required, well drilling and completion execution with severalrigs, the infrastructure build required to support the project team's work andto prepare for the production phase. The UO is now producing the field andexecuting further well and facility expansion work following handover of theproject's facilities from the IPT- Technical Operator. The project was executed at a record pace; success with in-country activitybeing critical in any final judgment of the project as an overall success. Thein-country work set out to ensure that positive precedents, standards andlegacies were set. At all times the highest international standards wereapplied. For example, from the very start due consideration was applied in HSEimpact assessments and required capabilities, local content and capacitydevelopment, national employment and development, and community engagement. Anextensive Environmental and Social Impact Assessment (ESIA) was carried outwith thorough public consultation. The field is run under an independentlyverified Safety Case creating a new standard; currently not a statutoryrequirement. This paper describes the in-country implementation, the high standards appliedto deliver success, the precedents set and examples of the challenges facedwhere activities did not proceed as expected. The implementation ofleading-edge project and field management technologies was carried out in a newcountry setting in a fast moving project. Examples of this are presented inwell engineering, logistics planning and field management information systems. The new country setting was a success factor and was an enabler where a longterm view is taken of the need to involve and benefit all stakeholders. Workcontinues to progress the field development and also the long term developmentof local personnel competency and capability, local content and communityprograms. The Jubilee project stands as a successful modern case history in a country newto major oil production. The approach taken was supported consistently andactively by the Government of Ghana and the Ghana National PetroleumCorporation. The impact has raised Ghana's profile and its level of economicactivity; encouraging further investment. The project establishes a base linefor the expected future growth of the Ghanaian oil industry. Introduction The Jubilee Field was discovered in June 2007 in the Gulf of Guinea, approximately 60 km offshore Ghana. It is a very large, light, sweet oilaccumulation in 1200-1500m of water. The Jubilee Partners including the GhanaNational Petroleum Corporation (GNPC) decided in January 2008 to develop thefield using a phased approach, after just one appraisal well. Kosmos Energy wasappointed Technical Operator to lead an Integrated Project Team (IPT) inexecuting the delivery of the development project and Tullow Ghana wasappointed UO to execute in-country activities, deliver wells and operate andmanage the field in the future. A third major Partner, Anadarko, providednumerous key project personnel. The IPT developed a plan to target just under300 million barrels in Phase 1 with a 17-well subsea well system and 120,000bopd FPSO. Phase 1 was approved by Partners in August 2008, and First Oil wasachieved in November 2010, within the aggressive time goal set by GNPC and theJubilee Partners. The Jubilee project background regarding its characteristicsand the project execution is described in references [1], [2], [3], [4], [5]and [6].