Summary In the past decades, many exploration wells have drilled into igneous rocks by accident because of their similar seismic expression to the common intended targets such as porous carbonate mounds, sheet sands or deepwater sand-prone sinuous channels. In cases where sedimentary features such as channels or fans cannot be clearly delineated, the interpretation may be driven primarily by bright spot anomalies, and a poor understanding of the wavelet polarity may compound this problem. While many wells that are drilled into igneous rocks were based on interpretation of 2D seismic data, misinterpretation still occurs today using high quality 3D seismic data. We propose an in-context interpretation workflow in which the interpreter looks for key clues or parameters above, below and around the target of interest to confirm the interpretation. Introduction Using modern 3D seismic surveys, significant work has been achieved over the past two decades in accurately imaging the geometry of igneous bodies (Hansen and Cartwright 2006; Holford et al., 2012; Jackson et al., 2013; Magee et al., 2014).
Global demand is expected to increase by 23%. The increase in expenditure is expected to be higher than the growth in vessel days due to the move toward higher specification vessels to cater to deeper and more complicated field development programs. Day rates for high specification dive support vessels (DSV) and multipurpose support vessels (MSV) are expected to increase by more than 40% by 2017. High specification flexlay day rates are expected to remain similar, while day rates for low specification flexlay vessels decrease marginally. Pipelay vessel rates are expected to increase by up to 8% for high specification, while light well intervention vessel day rates are anticipated to increase slightly.
An independent petroleum asset valuation is normally commissioned by a target company in defence of a hostile takeover bid.
A substantive study of petroleum company defence asset valuations is lacking in the published literature in hydrocarbon economics and other relevant journals. This study evaluates takeover defence valuations in the period ranging from 1988-2009 based on public domain data. The study focuses on assumptions for the key value metrics in the upstream valuations and how this has changed in the time period. This includes comparative reviews of publicly available data for four petroleum companies. This has been supplemented by published literature on assessment of value.
This paper examines the effectiveness of a completion technique where ball-activated sliding sleeves (BASS) are cemented into the wellbore. This technique allows operators to change zones between fracture-stimulation treatments by dropping balls from surface, instead of using the conventional pumpdown plug and perforating method. A five-well group completed with this method is compared to its direct offsets that were completed conventionally to draw conclusions. Initial studies show that this completion method reduces the time and cost to complete a horizontal well while yielding production that is equivalent to or better than the offset wells.
Preliminary research shows that the BASS group average 30-day Initial Production (IP) was approximately 25% better than the offset well average, and that the 9-month IP was approximately 33% better than the offset well average. Using the ball-drop completion technique, production increases were accompanied by faster completion times, a reduction in required hydraulic horsepower (HHP), and substantial cost savings. On average, wells that were completed using the cemented BASS showed no cost increase during the drilling phase, and reduced the mechanical completion cost by $20,000 to $40,000 per well when compared to offset wells. The primary efficiency driver during completion is the ability to prepare the well for fracture stimulation and complete multiple stages of fracture stimulation without having to utilize a workover unit. Additional time savings occurs between fracture-stimulation treatments; this method reduces downtime between stages from 3 hours to 20 minutes. This time savings can lead to more efficient use of equipment, which benefits the operator and the pumping company and improves community relations.
The Barnett shale is Mississippian-age marine shale that has proven to be productive when fracture stimulated. While most wells in the early development/exploration stage of the Barnett shale were vertical, the large majority of current wells are being drilled and completed horizontally. A common completion would be a production string of 5.5-in., 17-lb/ft, N-grade casing cemented through the horizontal section to provide zonal isolation and bring the top of cement up to cover the next productive interval. Once the casing is cemented in place, the drilling rig is demobilized and a workover rig is then mobilized to prepare the well for the first stage of fracture stimulation. The cement integrity is then checked by running a cement bond log. A workover rig can prepare the well in two days, with the first day being a bit and scraper run and the second day spent running the tubing-conveyed perforating equipment to perforate the holes to stimulate Stage 1. Once the first zone is perforated, a pump-in test can be performed.
When designing the completion, operators vary stage length from 150 to 550 ft, depending on the local geology, with shorter stages being used in areas where the Viola has pinched out, and longer stages being used in the areas where the Viola provides a suitable barrier from stimulating the water-bearing Ellenberger sands below the Barnett. The number of perforation clusters per stage varies greatly by operator, with some using a single-perforation cluster per stage, while others space six or more clusters as close as fifty feet apart. Many operators manipulate the perforation spacing and stage size in an attempt to control the height growth of the stimulation treatment, avoid stimulating potential geohazards, and target favorable rock.
The hazards of oil and gas facilities are well known to the league of operators, hardware providers, designers and lieges of contractors and consultants who work supporting the industry. Since Piper Alpha in 1988 safety is and has been a priority and the driver of countless modifications to ensure the well being of personnel in operating environments.
The oil and gas industry overall has shown a declining trend in fatalities and injury rates around the world demonstrating that learnings from mistakes have been taken on board so that they are not to be repeated. With the advent of deepwater production, bigger equipment items, changing field conditions and extended field lives, the financial rewards have become potentially even greater than ever to the industry, but at what risk?
The drivers are changing just like in the Le Mans 24 hour car race, the impact of safety risk is less prevalent as people are removed and other risks comes to the fore.
This paper discusses some of the issues that Granherne and the author has experienced in its provision of safety services to the oil and gas industry and provides an insight into how safety principles can still be focused even without the people present.
Before looking at some of the observed trends and risk challenges in the oil and gas industry it is important to ensure that some key definitions are understood.
Risk Trends and Challenges for Today's Industry
The following describes observed risk trends in the oil and gas industry that Granherne and the author have seen through consulting. Each risk trend is identified and key issues highlighted in order to promote discussion of some current and anticipated future issues.
Safety in Design
Designing a facility that is functional efficient and safe at reasonable cost has always been at the heart of the design process. Designers have always been aware of accidents at other facilities and have endeavoured to incorporate these learning's to ensure that the same accident does not happen again. It has been important since the advent of the Safety Case in Australia in 1995 that these learnings should always be incorporated into other operations. This philosophy is highlighted in both the Australian onshore Major Hazard Facility guidelines (Ref. NOHSC, 2002) and National Offshore Petroleum Safety Authority guidelines (Ref. NOPSA, 2004). This is also one of the key principles in the United Kingdoms HSE assessment for offshore facilities (Ref. UKHSE, 2006).