The Delaware Basin, a western sub-basin of the Permian Basin, is located in west Texas and southeast New Mexico. The industry’s focus on oil assets has influenced the resurgence in horizontal drilling activity in the basin targeting the tight sands and organic shales of the Bone Spring and Wolfcamp formations. The Avalon shale represents the organic-rich siltstones in the upper third of the Bone Spring formation.
Chevron drilled the Terra Nemo horizontal exploration well targeting the Avalon shale (~10,000 feet TVD). A robust formation evaluation was conducted which included a vertical and lateral logging suites, conventional core, side-wall core, well-site cutting analysis, and post-drill geochemical analysis of headspace gas, mud gas, and produced liquids. Ultimately, petrophysical logs plus well-site cutting and gas (C1/C5 ratio) analysis were used to identify the optimal landing zone. The Avalon shale shows moderate generation potential and uniformly type II/III kerogen (oil and gas prone). The targeted Avalon zone showed low levels of maturity based on Rock Eval analysis, consistent with incipient generation of liquids. Geochemical parameters (Oil Saturation Index) indicate low levels of liquids concentration throughout the pilot and lateral sections. However, elevated TOC values were observed along the lateral section with varying heavier gas ratios. Changes in the heavier gas concentrations generally correlated with increases in molybdenum, selenium, uranium, and vanadium. Detailed rock-typing was conducted to better understand the relationship of hydrocarbon occurrence with lithology. Tracers were used in the completion with early results suggesting ~75% stimulation efficiency with possible pressure shadows. This correlation of rock type, petrophysical logs, and completion response will be carried forward on future completion strategies as completion designs migrate from geometric to engineered. Imaging logs in the pilot and lateral showed drilling-induced and natural fractures in the target interval, which may have influenced production.
Identifying the type of fluid that will be produced at surface is a significant reservoir characterization challenge that is prone to error and uncertainty in an exploration environment. It usually requires rigorous solution of equation of state coupled with phase envelopes, which are usually available after drilling the well. These errors have significant impact on development plans and accurate reserves assessment.
With the introduction of advanced mud gas logging systems (AMG), quantitative assessment of gas data comparable to PVT analysis could be achieved while drilling. To get the most representative fluid typing results, a framework has to be established where local production data is compared to compositional data from PVT through model building techniques.
The successful application of this technique has many advantages; it allows accurate fluid typing in real-time for reservoir characterization. This information can impact a spectrum of decisions, starting from rig operations to simulation efforts.
In this study, decision trees, one form of artificial intelligence, are used to build a model that maps compositional data to production using local data sets. The resulting model is then used as a predictive tool to identify fluid types using AMG data while drilling before any other formation evaluation data, such as wireline logs, become available.
Crampin, Tom (Brunei Shell Petroleum Co. Sdn. Bhd.) | Gligorijevic, Aleksandar (Geoservices) | Clarke, Ed (Shell) | Burgess, Jamie (Brunei Shell Petroleum Co. Sdn. Bhd.) | Chung, Shao-Jung (Brunei Shell Petroleum)
Downhole determination of hydrocarbon phase is a significant subsurface challenge in many highly depleted fields. Reservoir production results in fluid compositional changes and variable hydrocarbon saturation distributions. Standard petrophysical techniques such as analysis of density and neutron porosity logs can give misleading results under such conditions. Most commonly, oil reservoirs can display a neutron-density response indicative of gas. There is significant business impact in error of hydrocarbon phase determination. Mistakes can lead to poor completion decisions, incorrect reserves estimation and suboptimal well and reservoir management.
The fluid phase uncertainty resulting from interpretation of standard Logging While Drilling (LWD) datasets can be unacceptably high. Additional tools or techniques are therefore required. Downhole fluid sampling is one such technique. It is routinely and successfully acquired in exploration and appraisal wells and gives robust fluid phase determination. However, it is not economically feasible for frequent acquisition for in-fill production wells where low cost LWD acquisition is the norm. In addition, overbalanced wells drilled through highly depleted reservoirs lead to acquisition risk in stationary openhole logging techniques. Advanced Mud Gas logging (AMG) is an established tool for delivering real-time quantitative fluid composition in exploration, appraisal and early production wells. However, successful applications in highly depleted fields have not been published as AMG analysis can be complicated by compositional changes. In this paper we present a case study calibration of AMG with downhole fluid samples resulting in a robust, cost effective and safe tool for improved hydrocarbon phase determination in depleted reservoirs.
Many techniques are used to determine hydrocarbon phase but all of them can be impacted by production related changes to reservoir fluids. The neutron-density "cross-over?? is the most common gas identification tool (Figure 1). It results from an anomalously low neutron porosity reading in gas, due to low hydrogen index (HI), and an anomalously high density porosity reading, due to low fluid density. A second traditional technique is the neutron near count to far count ratio. The near detector reads largely in the near wellbore invaded zone where high mud filtrate saturation results in a high HI and a relatively low count rate when overlain with the far detector, which reads deeper into the formation, past the invaded zone, resulting in a relatively high count rate if gas is present.
As the industry continues to expand into ultradeepwater plays, an increasing number of tight tolerance wells warrant the use of an efficient system for determining early influxes or losses during drilling, tripping, and cementing operations. The narrow mud weight window for the majority of these wells requires an advanced solution in order to operate in all such conditions without compromising on safety. This paper describes a new early detection flow monitoring system and setup for floating rigs, and presents its application via a case study of a very high-profile ultra deepwater well.
Good well surveillance for floating rigs requires precise measurements combined with an efficient smart process adapted to deepwater conditions in order to raise a reliable alarm in any condition, while minimizing the risk of false alarms. Careful sensor selection and sizing, together with particular attention to installation is required in order to achieve this degree of accuracy for all the drilling phases. The solution described in this case study provides drilling surveillance for all hole sizes, with flow up to 2000 gpm for accurate and early detection, and significantly increased safety during drilling, tripping, and cementing operations.
This case study describes how kicks can be detected with a high degree of reliability much earlier than with the standard pit volume and flow paddle monitoring. In addition to this, it has shown its value by characterizing, in real time, the consequences following a packoff event and also by differentiating between a wash out and pump failure.
Crew confidence in this detection system rapidly led to modifications of the operational procedures. For instance, flow checks were previously done for every pipe connection, taking up expensive rig time. Due to results obtained in the previous hole sections, the drilling procedures were updated in order to significantly reduce time spent flow-checking, while still maintaining maximum safety during the operations.
Real time digital slickline services have been used increasingly in the Gulf of Mexico by a number of customers. Through its telemetry enabled capabilities and the purpose built tools that complete the platform, digital slickline services can deliver a number of safety and efficiency gains to all types of slickline operations.
Material presented in this paper will be from actual operations, examples being perforation, tubing punching and cutting, plug setting and cement dump bailing, and will demonstrate the operational efficiencies being delivered.
Enhancement of the slickline service comes from real time surface readout of in situ tool operational status, the critical core measurements of downhole toolstring movement, deviation head tension and shock, and the depth precision now offered through gamma ray and CCL sensors. Optional tools such as a pressure / temperature gauge bring yet further visibility on the impact of the downhole actions undertaken. Expansion of the slickline service capabilities come from the telemetry enablement and core tools, coupled with a range of specific tools and sensors that have been developed to run on this slickline platform, namely a electro-hydraulic setting tool, an explosive triggering device, a monobore lock mandrel, and a production logging suite.
The real time data that is delivered to the slickline operator removes the need for assumptions that often have to be made during conventional slickline operation, and allow for a more efficient and reliable slickline operation to be undertaken. This results in a reduction in operation time, and a reduction in unnecessary trips out of the well to check on the tool status or to validate depth. Furthermore, since digital slickline is able to carry out both slickline well preparation work and a range of remedial or measurement work often carried out on memory or eLine, these operations can often be conducted entirely utilizing digital slickline crew and equipment. This optimizes pre- and post-job logistics, equipment rig up and rig down, and the job execution itself. In addition to the obvious cost savings, with a slickline wire comes a simplification of the pressure control and a well control recovery situation.
Loermans, Ton (Saudi Aramco) | Bradford, Charles Martin (Saudi Aramco) | Kimour, Farouk (Geoservices) | Karoum, Reda (Geoservices) | Meridji, Yacine (Saudi Aramco) | Kasprzykowski, Pawel (Geoservices) | Bondabou, Karim (Geoservices) | Marsala, Alberto Francesco (Saudi Aramco)
Loermans, Ton (Saudi Aramco) | Kimour, Farouk (Geoservices) | Bradford, Charles (Saudi Aramco) | Meridji, Yacine (Saudi Aramco) | Bondabou, Karim (Geoservices) | Kasprzykowski, Pawel (Geoservices) | Karoum, Reda (Geoservices) | Naigeon, Mathieu (Geoservices) | Marsala, Alberto (Saudi Aramco)
While traditional mudlogging techniques provide largely qualitative data, the objective of Advanced Mud Logging (AML) is to provide quantitative real time measurements and information in aid of drilling and a complete formation evaluation. Hence, during the past few years, various techniques which before were limited to laboratories, have been adapted for well site usage. Also, the whole surface logging system, from sensors to computer operating systems, have been enhanced.
A systematic comparison of results between laboratory instrument and field version instruments proved that the quality of results does not need to be given up when applying these techniques at the wellsite. At present AML well site techniques thus include (i) enhanced monitoring of drilling parameters, (ii) sophisticated mud gas analysis capabilities, (iii) enhanced cuttings image acquisition and processing, and (iv) several direct petrophysical measurements on cuttings.
We present some results of several field tests done in Saudi Arabia with a dedicated AML unit, where all these new techniques have been integrated. In this unit, next to conventional techniques, such as calcimetry, measurements on cuttings include X-ray diffraction (XRD), X-ray fluorescence (XRF), Nuclear Magnetic Resonance (NMR), spectral GR, grain density and porosity.
Examples in each of the four areas mentioned above confirm the potential of AML. AML mud gas analysis gives quantitative compositional HC analysis which perfectly matches results from PVT tests done on subsequent wireline fluid sampling. Also: while the depth resolution of mudlogging measurements, typically several feet, is less than of especially wireline logging, normally
sampled at half foot increments, the latest AML NMR measurements have the potential for very high resolution measurements, making it possible to establish the petrophysical properties of very thinly laminated sequences, where normally neither conventional wireline logs nor core plug measurements can resolve those.
Nassereddin, Tareq (Abu Dhabi Co. Onshore Oil Opn.) | Baslaib, Mohamed Ahmed (Abu Dhabi Co. Onshore Oil Opn.) | Abdelnour, Karim (Geoservices SA) | Elgamodi, Anwar (ADCO) | Al Hammadi, Ali Mahmoud (ADCO) | Mottet, Benoit (Geoservices) | Burnett, Stephen (Geoservices Middle East)
A common cause of failure with Surface-Controlled Sub-Surface Safety Valves (SC-SSSV) is a defect in the downhole hydraulic line, which controls the valve from surface. Such a failure (Control-Line (CL) leaking or plugged) generates production losses and requires the intervention of a costly workover rig - usually not immediately available. A large number of wells have been closed in due to CL problems.
This paper presents a pilot test of a "control-line free?? Wireline-Retrievable (WR) SC-SSSV concept, which replaced a conventional Subsurface Safety Valve and maintained the well producing under surface controlled conditions without the need for a work over or wellhead modifications.
A Wire line retrievable, flapper type self-equalizing Safety Valve has been interfaced with an HPU (Hydraulic Power Unit) and downhole electronics, which are operated by an electromagnetic signal transmitted from surface through the formation and using the conductivity of the tubing. The surface emitter continuously sends a signal (low frequency) to the SC-SSSV. As the system is designed to be fail-safe, the normally-closed valve remains open while receiving the signal and closes as soon as the signal is lost.
This control line free SC-SSSV can be set in any landing nipple profile. It has been installed by normal wire line operation in active onshore oil producing well for three months using a standard SC-SSSV lock mandrel.
25 periodic functional tests consisting of closing the valve and bleeding down the tubing pressure to confirm the integrity of the well pressure containment below the closed valve were performed for validation.
The primary application is to secure wells with a damaged CL or wells completed without any SC-SSSV. It provides an immediate cost-effective solution - allowing production to resume with a surface-controllable safety barrier while avoiding or postponing an expensive work over.
The pilot test has been successfully carried out over the 90 day period in a harsh environment onshore well usually equipped with SC-SSSV. The wellhead was fitted with two sensors: one pressure transducer on the flow line and one temperature probe connected to the surface emitter (for fire hazard detection) to act as temporary ESD for this test. Adjustable thresholds were set to switch off the surface emitter and shut-in the well in the event of any anomalies. Two unplanned events occurred during the 90 days pilot test: a temperature probe breakdown and a surface antenna disconnection. In both cases, the EM-signal was interrupted
and the SC-SSSV closed and secured the well.
Temporary solutions, such as the normally-open velocity or ambient valves, can be considered according to current safety policy but lacks ability to be connected to an emergency shut down system. The Electromagnetic "control line free?? SC-SSSV provides an effective and reliable surface controlled solution in the event of control line failure, or lack of hydraulic control system, on a standard SC-SSSV installation tied in to an existing emergency shut down system.
This breakthrough wireline product has proven to be easy to install and offers new possibilities for managing in a safe and effective manners the unexpected failures of hydraulic SC-SSSV.
In the Automated Drilling Pilot three newly developed technologies aiming to improve the quality of the drilling operation, have been submitted to an extensive offshore field test in the North Sea. The technologies involved were: (1) Software for drilling control automation based on real time process modeling, (2) system for drillpipe tracking based on RFID technology and (3) sensors for continuous measurements of drilling fluid parameters. During this field test the listed technologies were not only tested simultaneously, but also set up to exchange data in real time, forming one integrated drilling automation system.
In this paper the relevant functionalities of the technologies tested in the pilot are described. The paper also outlines the preparations for the pilot, including work performed on risk mitigation, onshore testing and training of personnel. In addition, the actual field performance of the technologies have been measured and evaluated regarding their influence on a number of important operational areas such as HSE, operational efficiency, work tasks/responsibilities and demands on surrounding technology. Lastly the capability of these technologies for exchanging data in real-time to form a closely integrated automation system has been demonstrated and evaluated.
Based on the experiences from the Automated Drilling Pilot, several crucial technology enablers have been identified for the technologies involved, the most important being related to personnel training/experience building, drilling data quality/availability and offshore expert support.
This reference is for an abstract only. A full paper was not submitted for this conference.
A common cause of failure with surface-controlled, subsurface safety valves (SC-SSSV) is a defect in the down-hole hydraulic line, which controls the valve from the surface. Such a failure generates production losses and requires the intervention of a costly workover rig - usually not immediately available. In order to alleviate this type of situation, a "fail-safe" safety system based on electromagnetic waves (EM) was developed in order to communicate with Downhole Safety Valves (DHSV) without the need for a physical control-line. The surface emitter continuously sends a signal (low frequency) to the SC-SSSV downhole. Both items are designed to be fail-safe. The normally-closed valve remains open while receiving the signal and closes as soon as the signal is lost. This innovative "control-line free" Wireline-Retrievable SC-SSSV can be set in any landing nipple profile or anywhere in the tubing using monobore lock technology without a workover or well head modification. The primary application is to secure wells with a damaged control-line (blocked or leaking), a damaged SC-SSSV landing nipple, or wells completed without an SC-SSSV. It provides an immediate cost-effective solution - allowing production to resume with a surface-controllable safety barrier while avoiding or postponing a costly workover. A pilot installation was completed in November 2008, at the BU-HASA field onshore UAE, in a well having an SC-SSSV with control-line. An electromagnetic surface controlled wireline-retrievable DHSV was installed at a depth of 142 ft on the SC-SSSV landing nipple. The anchoring was equipped with upper and lower V-packing assemblies to isolate the existing hydraulic control line from the well. The well head was temporarily instrumented with two sensors: one pressure transducer monitoring the flow line (with adjustable thresholds) and one temperature probe connected to the surface transceiver (to detect any fire hazard) and to switch off the transceiver in the event of a problem. To transmit the EM-signal, one mono-conductor cable was directly connected from the transceiver to the well head without necessitating any well head modification or disassembly. The second cable was connected to a water well located at 50 meters from the eruptive well. The control panel was deployed in a harsh environment near an ATEX area in zone-1; thick dry sand formation did not affect the transmission of the electromagnetic signal. The downhole equipment was easily set and retrieved by a slick-line crew. The setting up of all the equipment requires no more than one day's work. Two unplanned events occurred during the three-month pilot test: a pressure gauge breakdown and a surface antenna disconnection. In both cases, the EM-signal was lost and the DHSV closed and secured the well. These functional tests, so-called "slam tests" of the downhole tool were in total compliance with the expectations of the client. Another feature, "radio silence" mode, controlled from the surface, can be useful when some other work using EM is taking place near the well head. This breakthrough slickline product has proven to be easy to install, reliable and "fail-safe". It offers new possibilities for safely and efficiently managing the countless failures of hydraulic SC-SCSSVs. Sub-standard and temporary solutions, such as the normally-open velocity and ambient valves, no longer need to be considered. The control-line free DHSV concept also allows the hydraulic SC-SSSV landing nipple to be made available to install a device like a capillary string for chemical or gas injection at the bottom of the well safely. This versatility brings a reduction in production losses and provides the user with a cost-effective and reliable solution. Hundreds of wells are concerned in the Middle East; and probably thousands around the world.