A low-density direct emulsion (DE) system has been successfully formulated to minimize formation damage in mature depleted fields.
Key objectives for the DE system are to provide all the functions of traditional reservoir drill in fluids (RDF) in terms of efficient cutting suspension and carrying characteristics, effective fluid loss control and friction coefficient, while minimizing overbalance on depleted formations. Excessive overbalance on the formation would potentially cause severe losses and could result in formation damage, with negative impacts on the environment, and an increase in overall fluid cost. This novel oil-in-water DE system consists of a dispersion with oil as the internal phase, and water as the external phase. It targets densities less than 8.17 lb/gal to minimize overbalance on the formation while providing all the benefits of an emulsion system – enhanced friction reduction, effective fluid-loss control, superior rheology for hole cleaning and minimal ECD, and effective clay inhibition.
Numerous attempts of using DE systems in oil field drilling fluids have been made in the past. However, DE systems have never been fully accepted in industry due to difficulties maintaining the emulsion stability and its sensitivity to common contaminants. A novel thermodynamically stable DE system has been successfully formulated and used to drill a well with no excessive losses or emulsion stability issues.
The paper will present a detailed study of the laboratory development of the DE system along with field application data and lessons learned.
This paper presents the technical features and the associated benefits of a new integrated expandable under reamer technology, and showcases the field testing of the technology in the Brage field at offshore Norway and the achieved results.
Historically, the overburden stratigraphy at Brage field has been challenging for drilling. The unstable green clay and Draupne shale formation, the casing and completion programs and Equivalent Circulation Density concerns associated with drilling extended reach wells necessitate hole enlargement while drilling. In particular, the 12 ¼? section has a planned Total Depth (TD) right below the Draupne shale, inside which the calcite stringers also present, and a near bit reamer significantly increases the likelihood of getting down the 10 ¾" casing.
A new integrated under reamer technology was utilized to address the challenges in drilling five sections of a well in Brage: 14 ¾ ? × 17 ½?, two 12 ¼? × 13 ½? sections and two 8 ½? × 9? sections. The new under reamer is fully integrated with the company's rotary steerable system, which enables unlimited on-demand activation and deactivation cycles through downlinking with each cycle taking less than 5 minutes, flexible and optimal placement of the reamer in the bottom hole assembly (BHA), and real time feedback from downhole. The flexibility of the placement in BHA allows the under reamer to be used as a near bit reamer, a main reamer, or both. When used as a near bit reamer, the reamer can reduce the rat hole length to a minimum of 4 meters in the same drilling run, eliminating the need of a dedicated rat hole elimination run. The real time feedback includes confirmation of the blade activation status and a hole opening diameter log, reducing operational uncertainties for under reaming and saving rig time for a shoulder test that is otherwise required.
The technology proved its effectiveness as a reliable main reamer as well as a near bit reamer for rat hole elimination while satisfying all requirements for directional drilling and enabling Measurement While Drilling (MWD) and Logging While Drilling (LWD) measurements. For the 12 ¼? × 13 ½? section, both main and near bit reamers were activated simultaneously while drilling the last 68 m to TD and a good drilling performance was observed from the run.
The new technology provides unique features such as unlimited cycles of activation and deactivation through downlinking, flexible placement in the BHA and real time confirmation of blade activation status and hole opening diameter. The paper will describe these features in detail, and demonstrate how they can help the operators to reduce operational risks and save cost. It will also showcase a unique drilling application where three cutting / reaming elements in the BHA are actively present simultaneously and the associated drilling performance.
This paper discusses the methodology involved in evaluating the risks associated with drilling extended-reach wells using conventional drilling tools and adopting a stepped approach towards the drilling optimization of 25,000-ft total depth wells, with horizontal legs exceeding 14,000 ft. Extensive planning was carried out over the following areas of the project: well-trajectory design, torque and drag, the fluid program, drilling practices, drillstring design and integrity, hydraulics management, drilling optimization tools, and bottomhole assembly (BHA) design.
The objective was to drill two horizontal wells in the Bakken and Three Forks formations in North Dakota and to use the lessons learned to drill three extended-reach wells with 50% percent longer laterals. The first two wells of the project were studied to calibrate torque-and-drag models for hole friction, drillstring dynamics with the effects of fluid in-hole drag, effects on rate of penetration with regards to weight transfer while sliding, hydraulic effects of the fluid system, motor output, vibrations analysis, drilling practices through transitions, and parameter optimization while drilling through formation markers through the horizontal leg of the well.
The first two wells were drilled using a drilling-optimization downhole tool placed above the motor that measures the weight, torque, and bending moment across the sub. The pressure-while-drilling tool was also used. Tri-axial vibration sensors were used to measure and transmit data in real time to optimize drillstring dynamics and make improvements in the drilling system post run. The improvements in the system and lessons learned were used for three additional extended-reach wells with measured depths over 25,000 ft. Drillstring dynamics from the downhole sub were studied to identify ways to overcome friction. The data validated the effectiveness of certain friction-breaking tools and proposed areas for improvement to orient drill with conventional motors further into the lateral. The limitations with the current system were identified with the first two horizontal wells. Wellbore-trajectory design and pipe placement were optimized to aid in transferring weight to the bit beyond the 10,000-ft lateral horizontal leg. Alterations in the drilling program were subsequently made to drill further into the lateral based on lessons learned from downhole optimization tools and surface sensor data.
Three wells were drilled beyond a 25,000-ft total measured depth, with the horizontal leg exceeding 14,500 ft in the lateral. Continuous improvements were made to the system to drill to the limit with conventional motors and to pick up sophisticated rotary steerable tools to drill the last 1,500 ft of the lateral. The approach proved more cost effective to optimize within the constraints of the drilling system before using sophisticated rotary steerable tools.
Indo, K. (Schlumberger) | Pop, J. J. (Schlumberger) | Hsu, K. (Schlumberger) | Qi, J. (Schlumberger) | Agarwal, V. (Schlumberger) | Garcia Mayans, A. (Schlumberger) | Ossia, S. (Schlumberger) | Haq, S. A. (Schlumberger) | Varughese, J. (Schlumberger)
Over the last two decades downhole fluid analysis (DFA) using visible and near-infrared spectrometry has proven to be one of the most effective means for obtaining accurate and detailed reservoir fluid property information during formation tester operations. In a previous publication (SPE 166464) a methodology was introduced for estimating fluid properties, such as fluid type, hydrocarbon composition (C1, C2, C3, C4, C5, and C6+), carbon dioxide content, and gas/oil ratio (GOR), from downhole optical spectrometer data acquired during sampling operations. We have extended the methodology introduced in the previous publication to the real-time estimation of asphaltene content of black oils.
The equation derived for quantifying the asphaltene content of crude oils uses optical densities (OD), the absorption coefficients of asphaltene and resin, stock tank oil (STO) density, resin content and formation volume factor (FVF). In the process of deriving the asphaltene content a new method was devised for estimating FVF from optical data. The unknown parameters in the equation and the uncertainty in the estimate of asphaltene content are calibrated against a database that contains asphaltene content data of various crude oils and the corresponding optical spectra. Using the derived equation, a maximum likelihood estimate of asphaltene content of crude oil and its associated uncertainty can be obtained.
The accuracy of the method for estimating FVF and asphaltene contentwas verified and validated using laboratory crude oil data. The method was also applied to downhole optical spectral data acquired during a sampling-while-drilling (SWD) operation. It was found that the estimated asphaltene content and FVF obtained from the measured downhole spectral data showed very good agreement with the results of laboratory pressure/volume/temperature (PVT) analysis performed on captured fluid samples.
Health, Safety and Environment (HSE) practices and regulations have been of paramount importance to the Oil & Gas industry for decades. Drilling operations represent a major HSE risk and therefore robust programs have been put in place by Operators and Service companies to minimize the risks and ultimately reduce incidents. The success and sustainability of these programs has been well documented with quantifiable results, but the techniques have been rarely expanded to other operational areas. This paper reviews the field application of these HSE techniques on other areas of drilling operations and describes the results of the implementation over several years of offshore drilling experience.
One of the HSE techniques used in this case study is known as "Chronic Unease", a state of mind that has been successfully integrated into safety programs to build a methodology based on the recognition (detection) and reaction to weak signals that could potentially lead to significant events. As such it presents strong similarities to the early detection of drilling risks that could be prevented through quality programs.
This paper re-introduces the concept of "Chronic Unease" and presents how it can be mapped to Quality Assurance and Quality Control techniques in drilling operations. It also reviews the field application of other HSE techniques and describes the results of their implementation in several case studies in offshore drilling operations. Ultimately the case study illustrates a correlation between drilling efficiency and the successful re-purposing of proven HSE techniques.
Highly engineered, custom-built offshore platform designs begin with a simple plan to succeed based on managing complexity and risk, yet ultimately, the majority fail to meet the delivery, budgetary, and performance expectations that were identified at the beginning of the project. A significant amount of the Oil & Gas industry's largest facility undertakings were also discovered to fail in one, if not all, of the areas of hitting production targets. Those that were considered successful often achieved these results alongside documented longer deliveries and higher budgets from the outset, and very few that were discovered had best in class performance matching the development of Mobile Offshore Drilling Units (MODUs). This paper looks at the underlying causes of this phenomena and identifies patterns of execution and best practices for succeeding in an inherently complex construction environment. Two projects stood out and the best practices have been researched and compared to a third construction project with similar attributes, which are all discussed in Part One of this paper.
In Part One, the first two projects had well-defined relationships and outcomes and the third project suffered due to attempts to eliminate costs and a dysfunctional relationship between the driller, shipyards, and operator. All three projects were ultimate successes for the oil company. Part Two of the paper we look at the impact of the emerging practice of standardized drilling facilities that eliminates cost and complexity. We discuss in Part Three current drivers in our contracting model, and then Part Four introduces lessons learned from the recent build out of the MODU fleet. In the end, we will highlight how we as an industry can take advantage of the crisis of cost management in a low oil price environment. The theme of industrialization of the construction process is developed from the first two projects and carried into the MODU fleet, which implies that better performance is achievable and the overall complexity and cost of drilling facilities on platform rigs can become a reality.
Drilling time and cost were reduced in the Eagle Ford through the implementation of techniques and processes that resulted in 52% improvement in time and 45% reduction in cost.
The shale revolution sparked an aggressive development campaign starting in 2010 in the Eagle Ford. Wells were drilled with a lack of appropriate knowledge of the area, without sufficient experience or proper equipment. Drilling costs were high but development was profitable due to the surge in oil prices.
Drilling wells in the Eagle Ford is challenging because of the differences in lithology throughout the well, pore pressure profiles, high temperature, geosteering requirements, and casing design. These challenges had to be addressed in the design and execution of the wells. In addition, multiple trips due to downhole tool failures and low rate of penetration (ROP) contributed to high non-productive time (NPT) and associated costs.
When Statoil took over the operatorship in the Eagle Ford an integrated approach to engineering and operations was key to optimize performance and bolster understanding of the area. Application of technology and standardization of operations resulted in continuous performance improvement. Detailed planning and execution, application of rotary steerable, implementation of an optimized casing design, contractor performance management, clear and open communication within the team, implementation of a performance incentive plan, and proper risk management all played a part in the overall drilling performance improvements.
Over the past 2 1/2 years, more than 100 wells have been drilled in the Eagle Ford by Statoil. The techniques and procedures applied to optimize operations resulted in valuable lessons learned that can be applied to other development programs in the Eagle Ford and similar areas.
Kristjansson, Sean D. (Pason Systems Corporaton) | Neudfeldt, Adam (Pason Systems Corporaton) | Lai, Stephen W. (Pason Systems Corporaton) | Wang, Julian (Pason Systems Corporaton) | Tremaine, Dean (Axia NetMedia Corporation)
Despite recognition by the drilling industry that historic data can be used to inform the efficiency of drilling operations, published research into methods to systematically exploit historic data for this purpose are relatively scarce. In the present paper, we describe a novel method and automated solution that does just this it was developed for land-based wells drilled on the same pad or in similar geologic formations (i.e., offset wells), and it uses machine learning to search the offset data for epochs of highly efficient drilling. Once these epochs are identified, drilling parameter settings including weight on bit (WOB), drill string or drill bit revolutions per minute (RPM), differential pressure (?P), and pump rate (total pump output; TPO) settings linked to the highly efficient drilling epochs are extracted from the offset data. These settings then are formation- and depth-aligned to the new well to be drilled, and they are smoothed and displayed on the electronic drilling recorder (EDR) in real-time as "drilling parameter roadmaps." Such roadmaps were created for surface, intermediate, build and lateral sections for two trial wells. Trial results indicated that the average rates of penetration for the trial wells exceeded the average rates of penetration for the offsets by 20.1% and 47.8%, and time to drill the trial wells (i.e., spud to target depth) took 4.3 and 4.1 fewer days compared to the average number of days for the offsets. Per-day cost to operate these rigs was approximately $80, 000 suggesting our solution yielded substantial cost savings.
Drilling systems automation depends on timely flow of accurate and relevant data from multiple sources to control equipment, machines and processes. The fragmented nature of the drilling operations business means that data must usually be shared among companies contracted to perform services, and the operator, and all companies must trust that data. This paper describes the issue of data ownership in terms of the application of drilling systems automation, and proposes solutions.
Various parties in a drilling operation measure, collect, analyze and report data gathered during the drilling operation. They take actions to control the drilling process, avoid problems and improve performance, using information derived from the data. Data is used in pre-job planning, in real-time by those operating the drilling rig and various drilling tools, as well as periodically to advise the onsite drilling team. Data flow ranges from high-frequency, low-latency response loops at the wellsite to low-frequency, high-latency response loops in remote centers.
The SPE Drilling Systems Automation Technical Section (DSATS) has identified OPC UA as the most suited communications protocol for multidirectional fast-loop control systems. In these environments, there is high likelihood that a controller from one supplier will access and use data created by another supplier.
Drilling systems automation requires structured and organized data sharing between parties. This data sharing adds value to the drilling process. A conceptual data model describes at least three classes of data generated while drilling, and all lie within the confidentiality envelope of the operator or government agency. There is data that is the property of the data generator (such as equipment condition monitoring data), data that is restricted (such as formation evaluation data), and data that is shared in an "open data pool" for the purposes of drilling systems automation. Because ownership or control means responsibility for data quality, it is important that each data generator own its contribution to the shared data pool. The data aggregator – the party managing the shared data pool – is therefore not necessarily the owner of all data in the pool, but a caretaker of that data.
This paper describes the history of data measurement, data flow and data ownership in the drilling industry. It will address data ownership issues pertaining to drilling systems automation and drilling performance improvement. A brief review of examples of data from academia and from within our own industry will assist in understanding the relationship between data ownership and intellectual property. The paper presents a data ownership and data sharing solution that provides an environment for drilling systems automation.
Ure, John (Tullow Oil plc) | Peytchev, Peter (Tullow Oil plc) | Jha, Mihir (Tullow Oil plc) | Wenk, Andrew (Tullow Oil plc) | Mackay, John (Tullow Oil plc) | Anuar, Fendi (Tullow Oil plc) | Asbey, Thor (Tullow Oil plc)
The operator is involved in the exploration and appraisal of the South Lokichar basin in the Turkana region in remote north-west Kenya. The fields so far discovered are characterised by multiple pay zones spread over sand/shale sequences of 800 – 1,000m in thickness, with the shallowest reservoirs at approximately 850 – 1,200m true vertical depth below ground level. Well total depths are in the range 2,300 – 2,500m measured depth below rotary table. Productive hydrocarbon-bearing zones to date have been sub-hydrostatic in initial pressure. The reservoir fluid is a waxy crude oil (24 – 37% wax content) with low, variable gas-oil ratio. Flow assurance is a key aspect of the completion design, due to the reservoir temperature of the shallower prospective zones being close to the wax appearance temperature.
Until late 2014 the drill stem testing of discovery and appraisal wells was rig based. Productive zones were tested in a ‘bottom-up’ sequence resulting in durations of 50 – 60 days for a five-zone drill stem test. The initial aim of well design activity was to increase testing operational efficiency, however the operator accelerated the area development planning as a result of the exploration and appraisal drilling success in the basin. Subsequently, completion design efforts were driven to meet a subsurface requirement for the acquisition of well test and transient interference pressure data from extended well testing involving five wells in two of the discovered fields (Amosing and Ngamia). The approach which has been successfully implemented, was to make all well testing rigless after the installation of a multi-zone intelligent completion, allowing the rig to continue appraisal drilling or well completion activity in parallel with these testing programmes.
This paper presents the completion design selected and the operational challenges which have been overcome by the operator in appraising these fields.