Africa (Sub-Sahara) Oil was discovered at the Ekales-1 wildcat well located in Block 13T in northern Kenya. The well has a potential net pay of between 197 and 322 ft in the Auwerwer and Upper Lokone sandstone formations. Tullow (50%) operates 13T with partner Africa Oil (50%). The Mzia-3 appraisal well in Block 1 off Tanzania encountered a combined total of 183 ft of net pay in the Lower and Middle sands and confirmed reservoir quality in line with that seen in the Mzia-1 and Mzia-2 wells. Asia Pacific The Luba-1 offshore well on Brunei Block L was spudded. The well will evaluate the hydrocarbon potential of the Triple Junction structure. Serinus has a 90% interest in Block L, through indirect wholly owned subsidiaries Kulczyk Oil Brunei (40%) and AED SEA (operator, 50%).
Africa (Sub-Sahara) Gas was discovered at two separate levels in the Mronge-1 well in Block 2 offshore Tanzania. The discovery is estimated at between 2 and 3 Tcf of natural gas in place, bringing Block 2's estimated total in-place volumes up to 17 to 20 Tcf. Statoil (65%) operates the Block 2 license on behalf of Tanzania Petroleum Development Corporation, and partners with ExxonMobil Exploration and Production Tanzania (35%). Oil was discovered at the Agete-1 exploration well on Block 13T in northern Kenya. The well, drilled to a total depth of 1929 m, encountered 330 ft of net oil pay in good-quality sandstone reservoirs. Tullow Oil (50%) is the operator with partner Africa Oil (50%). Asia Pacific Indonesia announced plans to offer 27 oil and gas blocks in 2014 in regular tenders and direct offers.
Africa (Sub-Sahara) BG Group discovered gas in the Taachui-1 well and sidetrack in Block 1, offshore Tanzania. The drillship Deepsea Metro Idrilled Taachui-1 close to the western boundary of Block 1, then sidetracked the well and drilled to a total depth of 4215 m. The well encountered gas in a single gross column of 289 m within the targeted Cretaceous reservoir interval. Net pay totaled 155 m. Estimates of the mean recoverable gas resources are around 1 Tcf. Statoil (65%) and co-venturer ExxonMobil (35%) made a sixth discovery--the Piri-1 well--in Block 2 offshore Tanzania. Piri-1 was drilled by drillship Discoverer Americas, at a water depth of 2360 m.
Africa (Sub-Sahara) Eni finished a production test on its Minsala Marine 1 NFW well, located in Marine XII block, 35 km offshore The Republic of the Congo. During the test, the well delivered natural flow in excess of 5,000 B/D of 41 API crude and 14 MMcf/D of natural gas from a 37-m opened section of the discovery's 420-m column. Eni (65%) is operator, with state-owned partner SNPC (25%), and New Age (African Global Energy) Limited (10%). Asia Pacific CNOOC started natural gas production from the Panyu 34-1/35-1/35-2 project at the Pearl River Mouth basin in the South China Sea. Main production facilities for the three gas fields include one comprehensive platform, two sets of underwater production systems, and 13 producing wells. Two wells are producing a total of 21 MMcf/D of gas. The project is expected to reach peak production of 150 MMcf/D.
Digital oil fields implementation is ongoing in various oil fields around the world since the last few years. There are many research initiatives focusing on performance improvements trying to eliminate Non-productive time (NPT) caused by equipment failures or drilling conditions but the Invisible Lost Time (ILT), which accumulates when common drilling operations such as drill pipe connections are not carried out efficiently, is neglected. This makes it difficult to compare well delivery time and performance discrepancies for each activity across a field. The main challenge in optimizing drilling performance is deciphering the rich data streams in real time to make informed business decisions. This study focuses on the integration and analysis of real-time drilling data in order to evaluate the drilling performance via Invisible Lost time.
The methodology starts with analysing the effectiveness of the Remote Monitoring (the backbone of Digital Oil Field) of critical drilling operations as the actual performance is compared with predefined operation practices in terms of Rig Performance, Individual Crew Performance and Section Performance over four unknown drilling wells located within Field-X in the North Sea. The Invisible Lost Time is quantified from selected drilling activities such as tripping, drilling, running casing and flat time operations that can result in significant potential savings other than the main drilling operations.
Histograms were utilized to improve rig performance which indicated that the Connection time can lead to significant days’ savings as Tripping time contributes to approximately 60% of the Invisible Lost Time (ILT). Additionally, the effect of various factors such as hole sections and well depth on potential savings was also studied. This strategy may be developed as a cost-effective technology for any drilling or workover wells, as it results in improving drilling key performance indicators (KPI's) leading to performance improvement, risk mitigation and cost efficiency in real-time drilling activities.
Ultrasonic velocities were measured across a variety of samples to link elastic properties with physical properties unique to coals, shaly coals, and coaly mudstones. P- and S-wave velocities have a positive correlation with both rank and inorganic mineral content in coaly rocks from New Zealand. The results compare to previous studies, which show increasing elastic wave speed as a function of organic maturity. In addition, they portray a greater change in elastic moduli (ΔK and ΔG), over increasing coal rank, than velocity (ΔV) or density (Δρ). VP/VS decreases from an average of 2.43 in subbituminous coals to 2.14 in anthracite and continues decreasing with increasing inorganic mineral matter. Further study may elucidate whether these relationships are useful to distinguish coaly rocks in the subsurface through forward modelling or seismic inversion. The comprehensive dataset from this study presents a new geophysical approach towards coaly source rocks. These types of petroleum source rocks are regionally significant, however; they are less common globally.
Fomin, Vitaliy (Halliburton) | Kushmanov, Pavel (Halliburton) | Purwar, Suryansh (Halliburton) | Aksenov, Mikhail (Halliburton) | Durygin, Nikolay (Halliburton) | Golovin, Oleg (Halliburton) | Solovyev, Iliya (IPOS) | Govorkov, Denis (TSOGU) | Vedernikova, Yuliya (TSOGU) | Iskakov, Daulet (TSOGU)
Gas condensate fields present unique challenges regarding data acquisition, data quality, exception-based surveillance, flow modeling, nodal analysis, well testing, allocation, and visualization. Although existing tools and methods address many of these aspects, it is possible to streamline processes and explore increased production efficiency methods. This paper addresses these challenges; it presents a case study of an intelligent control system implementation for a gas-condensate field based on a unified data model, integrated modeling, and cross-domain workflows.
This paper presents a transformative, intelligent, and automated work process, referred to here as "smart workflows." As part of these workflows, virtual gauges are used that are based on inflow models and lifts, adjustable valves, and modular networks. The workflows are implemented on a truly open end-to-end platform that enables the coupling of multiple databases, streamlining of data for an integrated analysis of the measurements and model calculations, and ascertaining the mismatch between the two. The workflows also initialize adaptive self-tuning procedures.
The smart workflows enable engineers to achieve various improvements, including an integrated structure of process data model to enable quick access to validated data, monitoring and control functions to a gas-condensate field in real time, and reduced downtime and operational costs. The smart workflow also supports functions that include collection and verification of measurement data, configuration of the integrated solution component models, evaluation of the action of root causes, and planning of operation scenarios.
As part of the implemented system, an integrated information system data structure sets the degree of relatedness of tasks, each of which can be initialized depending on work situations and/or operator commands.
Such comprehensive analysis of the data provides reliable integrated system configuration parameters of the model, which increases the accuracy of the calculations used in the optimal planning of the operational scenarios.
Singh, Deepak (CSIR-National Geophysical Research Institute, Hyderabad, India) | Kumar, Priyadarshi Chinmoy (CSIR-National Geophysical Research Institute, Hyderabad, India) | Sain, Kalachand (CSIR-National Geophysical Research Institute, Hyderabad, India)
The chimney effects also exhibit good correlations with seismic attributes when displayed over the horizon slices mapped over the formation tops. This study provides important inputs in understanding the petroleum system of the study region and acts as a preventive measure for mitigating geo-hazards in future drilling. Introduction The state-of-the-art image processing and visualization techniques have modernized the art of seismic interpretation. This has allowed interpreters to analyze more data with a greater accuracy in less time. Seismic attributes have played a pivotal role in interpreting seismic data.
Time-lapse, cased hole torque and drag (T&D) measurements and soft string T&D modeling were undertaken in two experimental horizontal steam injection wells for the purpose of assessing the integrity of the slotted liner completions over a 20 month period. A series of progressively complex completions were installed in the wells to manage steam conformance and measure steam injection flow profiles in this mobile, heavy oil application. This T&D work was done to understand if sand influx, scale and asphaltene deposition, or thermal strain damage was occurring within the slotted liner thus increasing the deployment and recovery risk of the tubing-deployed completions. For each injector, T&D measurements were repeatedly obtained at the same depths during each workover with the same 3-1/2 inch (89 mm) tubing string.
T&D data is inexpensive and easy to acquire during rig operations. Commercial software is readily available to model T&D and estimate cased hole friction factors (CHFF). Analysis of T&D in these wells did provide insights for sand influx and scale deposition. However, T&D analysis did not provide insights into all integrity problems encountered which included metal clamp debris that would not allow packers to be landed at the target depth and corrosion failures resulting in parted tubing. T&D measurement analysis is a useful integrity diagnostic in horizontal injectors, but needs to be supplemented with other information to get a complete picture of wellbore conditions. Considering the general lack of information that heavy oil operators get from the horizontal section of their wells, it is recommended that baseline cased hole T&D measurements be acquired on horizontal wells during initial completion with 0.1 Kip precision. Comparing both T&D measurements and CHFF's on subsequent workovers did provide insights on the stability of horizontal wellbore conditions.
The world's first deployment of an automated drilling control system on a Statoil rig in the North Sea helped the rig in saving up to 10% rig time per well through safeguarding and optimizing manual operations and through automating repetitive drilling activities such as tripping, pipe filling, connections and pump start up. Advanced modelling of well conditions, combined with closed loop control of the drilling control system provided safeguards for pressure, rotary and hoisting velocity.
The drilling instrumentation, surface- and downhole sensors are coupled with robust real-time and fully transient hydraulic, mechanical and thermodynamic models that continuously evaluate the current downhole conditions. These models determine all possible combinations of drillers' actions (string accelerations, velocities, rotation, pump start-ups and flow rates) that will cause the dynamic downhole pressure to reach or exceed upper and lower well stability- and geo-pressure prognosis. These results are actively used to safeguard both manual and automated sequences. For example should the driller attempt to pull the drill string at a velocity that would cause the downhole pressure to fall below the Pore Pressure or Collapse Pressure at any depth in the open hole section, the drilling control system will intervene and limit the upward velocity to a safe value based on the dynamic model.
The models effectively calculated and communicated current limits to the drilling control system, allowing the control system to safeguard the well against human error during manual operations and to automate various repetitive operations. Statistics after 3 wells proved an overall time saving of 4% per well through automated repetitive sequences (such as pump start-ups and friction tests) while another 2–8% time savings per well were realized through optimized manual operations (active safeguards and safety triggers) and other improvement initiatives by the rig. Although the system was originally developed to eliminate human errors and avoid major incidents (including technical side-tracks), the daily efficiency gains indicate that the system also avoids minor issues that otherwise would have slowed down the operation without being seen as downtime or Invisible Lost Time. This indicates that the system works as intended and that the system should be able to avoid major incidents when the relevant conditions arise.
This paper demonstrates how automation reduces invisible lost time and allows drillers to focus on other activities while repetitive tasks are controlled by software. Furthermore, rig safety is significantly enhanced since the closed loop drilling control system prevents users from exceeding the dynamic limits calculated by the drilling control system.