Pad drilling has become commonplace for North America shale development drilling, which requires tighter well spacing/separation and reduced anti-collision risk. A new digitally-controlled rotary-steerable system (RSS), extensively embedded with electronics, solid-state sensors and electrically controlled mud valve, has been developed specifically for drilling vertical and nudge well profiles from pads in North America. Unique technology includes a slow-rotating steering housing with four mud activated pads to apply side force at the bit. The pad activation is controlled using a novel mud valve driven by a low-power electric motor and gearing system. Activation of the steering pads and control of force to the steering pads is achieved using a small percentage of mud flow and approximately 500 psi pressure drop below the tool. The limited amount of mud flow passing through the mud valve eliminates internal wash issues and reduces repair costs.
The electronics measurement and control system are mounted in the slow-rotating steering housing and includes 3-axis inclinometers, 3-axis magnetometers, 3-axis shock sensors, 3-axis gyros, and temperature sensors. Additionally, compact drilling dynamics sensors are placed at the bit box to gather at-bit data to evaluate bit-rock dynamic interaction.
This paper will describe the unique features that allow the system to be reliable and cost-effective for high-volume land drilling activities. The RSS bottom-hole assemblies (BHAs) have been extensively instrumented with multiple downhole dynamics sensors, which reveal a challenging drilling environment unique to vertical drilling and nudge applications and show the performance of the RSS in this environment.
Gustavo, A. (Shell) | Ugueto, C. (Shell) | Huckabee, Paul T. (Shell) | Reynolds, Alan (Shell) | Somanchi, Kiran (Shell) | Wojtaszek, Magda (Shell) | Nasse, Dave (Shell) | Tummers, Richard (Shell) | Stromquist, Marty (NCS Multistage) | Ravensbergen, John (NCS Multistage) | Brunskill, Doug (NCS Multistage) | Whyte, Rio (NCS Multistage) | Ellis, Dustin (NCS Multistage)
Cemented Single Point Entry (CSPE) has the potential to reduce or eliminate the non-uniformity and Hydraulic Frac Stimulation (HFS) placement uncertainties inherent in other completion systems. If entry-to-entry isolation can be achieved, HFS initiation and treatment allocation near the wellbore can be better controlled by a CSPE completion. Fiber Optics (FO) and other diagnostics can provide the means to evaluate the effectiveness and potential benefits of this and other completion systems. This paper describes the HFS placement findings of a FO instrumented Coil Tubing activated CSPE well (CTa-CSPE).
Coil Tubing CSPE completions provide some additional frac diagnostic information. Pressure and Temperature (P/T) gauges located in the Coil Tubing Bottom Hole Assembly (CT-BHA) help to evaluate the isolation with prior stimulated stages. A newly developed sleeve, specially designed to accommodate a FO cable outside casing, allows the simultaneous acquisition of both P/T information from downhole gauges and high-resolution stimulation data from FO.
This paper shows several examples from stages with variable entry-to-entry isolation quality in a wellbore with 6000 ft lateral section. The results from the P/T gauges, Distributed Acoustic Sensing (DAS) and Distributed Temperature Sensing (DTS) are mostly consistent for all 69 stages in this well. Only stages where communication was observed toward the heel-side of the lateral, relative to treatment sleeve, show inconsistent but explainable results. CT-BHA P/T gauges are only capable of detecting communication toward the toe-side of the lateral. In this well some degree of communication occurred in 48% of all stages. Evaluation of the FO data across multiple stages shows that the path of communication between sleeves and slurry placement can be complicated. Integration of DAS and DTS indicates that the slurry, between adjacent and poorly isolated stages, travels behind the casing down to the prior sleeve and then inside the wellbore, where the slurry is partially re-injected into previously stimulated stages. This dataset clearly illustrates that no single HFS diagnostic provides all the necessary information to fully understand the complexities of HFS placement. In this well, the data from CT-BHA P/T gauges, DAS and DTS are clearly complementary. The data also indicate that there is an urgent need to improve isolation between stages. Cement quality seems to be the primary source of entry-to-entry communication in long horizontal wells for this and other completion systems. In this well alone we estimate several hundred thousand US$ were wasted from the misplacement of stimulation energy and materials (capital inefficiency). To capture the full value from CSPE "pinpoint-fracturing" and the corresponding more effective drainage of resource volumes between wells, the problems associated with entry-to-entry communication must be understood and corrected.
Finally, we will introduce some new multicycle sleeves that will further enhance the capabilities of CSPE systems. These sleeves are specially designed to obtain production profiling information via FO. Deployment of such systems should provide the industry with the means to better evaluate and optimize completions and wellbore spacing.
Verifying that conventional coiled tubing (CT) has entered the correct lateral of a multilateral well can be a time-consuming and tedious challenge. While passing the kickoff point (KOP), surface pressure sensors may not clearly identify that a hydraulic knuckle joint has entered the lateral. To verify which lateral has been entered, the CT must be run-in-hole (RIH) to tag the unique total depth (TD) of the lateral. It can be difficult to prove that the correct lateral has been entered if the TDs for two laterals do not differ significantly. If the CT tags before or after the expected TD is reached, then the operator must pull out of hole (POOH) and repeat this process.
This paper presents an improved method for detecting which lateral has been entered shortly after passing the KOP by using a real-time, fiber optic cable (RTFO) bottomhole assembly (BHA). The RTFO BHA is equipped with sensors for gamma radiation (GR), tool inclination, tool face, casing collar locator (CCL), internal and external pressure, and temperature. These readings enable the operator to use the CCL and gamma detector to correlate to the desired lateral’s pipe joints using an existing CCL/GR log. The tool face reading theoretically predicts which angle the knuckle joint should be indexed. The internal pressure sensor provides clear indication of pressure changes when a hydraulic knuckle joint has entered the lateral and the inclination sensor verifies that the inclination of the BHA matches the inclination of the desired lateral.
This paper discusses two dual-lateral water injection wells; the TDs of the laterals in the first well were equal, with no trait that conventional CT would be able to distinguish. In addition, the inclination of each lateral was very close to the other, making the difference of pipe weight, read from the surface, not significantly different enough to verify which lateral had been entered. However, with the RTFO BHA, the correct lateral was easily entered and verified, significantly reducing time, risk, fluids, and CT pipe fatigue, while providing assurance that the stimulation fluid was accurately placed.
This paper describes the first time that a flow-through gamma, inclination, tool face sensor module was deployed to accurately enter, identify, and stimulate a casedhole multilateral well without cycling the CT at the KOP, and without relying on tagging TD to confirm that the BHA is inside the desired lateral. The new process proved to be a better, more cost effective, and efficient way to stimulate multilateral wells. This solution can be used by operators to extend the life of their mature fields.
Dulaijan, Auda (Saudi Aramco) | Shenqiti, Mohammad (Saudi Aramco) | Ufondu, Kenechukwu (Saudi Aramco) | Zahrani, Bader (Saudi Aramco) | Abouelnaaj, Khaled (Saudi Aramco) | Shafiq, Muhammad (Schlumberger)
Following the success of the first installed intelligent completion system in Saudi Arabia in 2004, over 260 Intelligent Completion systems have been installed in a majority of Maximum Reservoir Contact (MRC) Multilateral (ML) wells. These intelligent completion systems have been successfully installed in openhole, expandable liners, expandable sand screen, Extended Reach Drilling (ERD) wells and also integrated with Electric Submersible Pumps (ESP). This technology has led enhanced oil recovery while reducing water production to surface. Water handling cost at surface is reduced by producing less water to surface and also shutting off downhole water production completely.
This paper covers some of the case histories of over ten (10) years of design, planning, installation, testing and optimization of intelligent completion systems in Multilateral (ML) Maximum Reservoir Contact (MRC) wells within Saudi Arabia. Production optimization practices and enhancement of production life in carbonate multilateral wells in the world's largest oilfield are also documented. Case histories highlighting how water production was remotely choked back, shut-off and production optimized from identified lateral without any intervention in the well are reviewed.
Advantages of intelligent completion technology for multilateral wells and the review of the downhole choke customization process that included design flow area after modelling well data for different flow rates and differential pressures are detailed. This is in addition to the integration of the surface control system to the production supervisory control and data acquisition (SCADA) system which provided real-time downhole pressure and temperature data and remote control of downhole flow control valves during the life cycle of the well. This paper also discusses a closed-loop approach which led to efficient real time production optimization. Performance review of how intelligent completion systems provide selective lateral control, delay water breakthrough, control water production, shut off wet lateral, reduce opex, optimize production, enhance recovery and reduce safety risks thereby minimizing future interventions are documented.
One of the main challenges in the oil industry is to reduce well intervention costs. This paper will explain the planning and execution of an application in the Middle East in which Radio Frequency Identification (RFID) technology has been incorporated into a Circulating Toe Sleeve (CTS) to close and operate the tool remotely. Using the remotely activated CTS tool eliminates the need for additional intervention equipment and subsequently reduces the operational cost and risk involved in isolating and testing liners in Extended Reach Drilling (ERD) wells.
The remotely activated CTS will be located at the toe of a plugged Pre-Perforated Liner (PPL). The RFID CTS tool will be run open so that the liner can be circulated in. When the liner assembly is at the desired depth, it will be activated either by circulating RFID tags to the tool or allowing a timer to elapse. Once the CTS has been closed, it will prevent communication between the liner and the wellbore, thereby functioning as a barrier and allowing the liner assembly to be pressure tested.
The use of a standard circulating toe sleeve to provide liner isolation would typically result in significant costs and risks for the operator. These could be incurred in intervention time, additional service personnel on location, and budgeting for the risks associated with intervention. In ERD applications it may not be technically possible to provide an intervention solution to all parts of the well, especially the toe section. The use of a remotely activated CTS can reduce all of these considerations and make ERD wells economical and technically feasible. The potential savings this technology can bring increase by an order of magnitude when applied offshore/subsea.
Jassem, H. (Saudi Aramco) | Al-Shehri, Ayedh M (Saudi Aramco) | Al-Shammari, Nayef S. (Saudi Aramco) | Al-Gamber, S. D. (Saudi Aramco) | Mutairi, K. M. (Saudi Aramco) | Said, R. (Saudi Aramco) | Barkat, S. (Schlumberger) | Ahmed, D. (Schlumberger)
The study well was first drilled as single lateral Power Water Injector (PWI), then sidetracked as a multilateral injector with a total reservoir contact of 23,094 ft. The well was completed with three new laterals all placed up-dip in the water leg. This geometry was specifically intended to increase injection potential and provide more pressure support in the lower transmissibility areas of the well's complex, carbonate field.
This paper discusses the Coiled Tubing (CT) accessibility challenges, technology deployment and lesson learned for stimulating the first quad-lateral extended reach PWI ever drilled in the study area in Saudi Arabia. The PWI is used to increase the injection capacity and provide extra support to reservoir pressure.
Due to the challenging extended reach well trajectory, technology unavailability, challenge of effectively access all 4 laterals and properly identify each later to stimulate them, CT with real time downhole monitoring was used in conjunction with a multi-lateral tool access. The multi-lateral tool (MLT) was used to provide controlled, oriented mapping to access each lateral independently. The indication for the correct lateral was confirmed by both downhole pressure drop across the multi-lateral tool. As all the laterals are extended reach, getting to total depth (TD) was challenging for some of the laterals even after implementing all the reach techniques. In order to be efficient and identify which lateral was accessed an innovative method was developed by using Gamma Ray (GR) tool and casing collar locator (CCL) to properly identify each lateral before having to reach TD to determine the lateral accessed.
Once the proper lateral is accessed and determined, the acid treatment placement was pinpointed to and optimized by distributed temperature survey (DTS), which helped determine in real-time high permeable thief zones and tight or damaged zones. The treatment schedule was designed to divert from high intake zones using viscoelastic surfactant diverting acid system, followed by hydrochloric (HCl) acid for stimulation. The intervention was completed successfully without any safety incidents. The use of GR, CCL and downhole pressure & temperature measurements in conjunction with MLT tool gave the ideal method for lateral access and lateral confirmation especially when reaching to Total Depth (TD) was not feasible due to CT lockup. In addition the use of DTS for optimum stimulation placement was the key in improving operation efficiency.
The methods developed in this paper on how downhole measurements such as pressure inside and outside CT and it's differential, CCL, GR, MLT and DTS can be used in Multilateral wells has proven to be a major success. This first intervention of its kind has opened new innovative ways and techniques of confidently stimulate all the multilateral extended reach wells in Saudi Arabia.
Ipatov, A. I. (Gazpromneft NTC LLC, RF, Saint-Petersburg) | Kremenetsky, I. M. (Gazpromneft NTC LLC, RF, Saint-Petersburg) | Kaeshkov, I. S. (Gazpromneft NTC LLC, RF, Saint-Petersburg) | Buyanov, A. V. (Gazpromneft NTC LLC, RF, Saint-Petersburg)
The pdf file of this paper is in Russian.
The authors sum up Gazprom Neft field experience in the area of longterm distributed temperature sensor (DTS) studies in horizontal wells. First steps in information capacity analysis were made on vertical multilayer well studies. Obtained results approved thermosimulator calculations and allowed to determine future conditions of representative studies in horizontal wells. The following periodical DTS measurements during multi-fracturing and 6 months stationary monitoring showed high information capacity of both stable and dynamic temperature field. The next steps in method effectivity enhancement are two be done in three directions: 1) DTS optimization, its components and price; 2) forming the best well run and stop conditions for easurements; 3) usage of advanced methods of interpretation and software. Most urgent field task is DTS installation in horizontal well with ESP. Exact technology is not provided yet (ESP housing, Y-tool or composite fiber rod). Anyway for tie-in and reliable interpretation basic production logging studies will be conducted before DTS installation. In its turn obtained results of distributed acoustic sensing are still to be comprehended and may also find its place in production monitoring system.
Обобщен практический опыт компании ОАО «Газпромнефть» в области адаптации и развития систем стационарного долговременного мониторинга температуры в горизонтальных скважинах с помощью распределенных оптоволоконных систем (ОВС). Первые шаги по изучению информативности метода сделаны при исследовании ОВС вертикальных скважин, вскрывающих многопластовые залежи. Данные исследований подтвердили результаты расчетов, выполненных ранее на термосимуляторе, расчеты и позволили определить условия проведения информативных исследований в горизонтальном стволе. Последующие периодические замеры в горизонтальных скважинах при операциях гидроразрыва пласта, а также полугодовой стационарный мониторинг показали высокую информативность измерения как стационарных, так и динамичных температурных полей в скважине. С целью повышения информативности метода планируется совершать в следующих направлениях: 1) оптимизация самой системы измерения, ее компонент и стоимости; 2) формирование технологических требований, связанных с формированием и стабилизацией режима отбора/закачки в процессе измерений; 3) применение современных средств обработки и интерпретации зарегистрированных кривых. Отмечено, что следующей актуальной производственной задачей является выбор наиболее эффективной технологии спуска ОВС в скважины механизированного фонда (кожух на электроцентробежном насосе, байпасная система или композитный жесткий кабель). Для привязки и интерпретации замеров ОВС планируется продолжить базовые замеры промыслово-геофизическими методами перед спуском стационарных систем.
Kychkin, A. V. (Perm National Research Polytechnic University, RF, Perm) | Volodin, V. D. (Perm National Research Polytechnic University, RF, Perm) | Sharonov, A. A. (Perm National Research Polytechnic University, RF, Perm) | Belonogov, A. V. (Perm National Research Polytechnic University, RF, Perm) | Krivoshchekov, S. N. (Perm National Research Polytechnic University, RF, Perm) | Turbakov, M. S. (Perm National Research Polytechnic University, RF, Perm) | Shcherbakov, A. A. (Perm National Research Polytechnic University, RF, Perm)
The pdf file of this paper is in Russian.
The efficiency of the hydrocarbon deposits development is determined by recovery factor of oil or gas and the amount of material costs for the development of mineral resources and their exploitation - profitability of the project. Today, science and technology allows to develop economically feasible deposits with hard to recover reserves by applying methods of stimulation to the well, one of the most popular is the construction of wells with horizontal profiles. Drilling of directional and horizontal wells require the use of special drilling equipment - rotary-steerable systems (RSS) to control the trajectory of the wellbore in real time. Today the market offers a large number of equipment for directional drilling the main is a foreign proceeding. Work with such systems need to attract highly qualified personnel, and often foreign experts. In this regard, the development of a remote monitoring and control system of the trajectory of the wellbore hardware and software while drilling wells using RSS is an actual scientific and practical task. The paper presents the set-theoretic model of the synthesis of the structure of remote monitoring and control system of the trajectory of the wellbore hardware and software while drilling wells using the rotary steerable systems. Approach to systematize the creation of software and hardware systems structure for monitoring and control provides qualitative information and algorithmic environment that meets all the requirements of modern standards. On the basis of the proposed model the structure of the complex is designed, which includes a set of submersible units, executive and implementing measurement and control system, communication system, scheduling system. The structure of hardware and software has a modular principle of organization, it involves building up features, including the introduction of additional telemetry parameters, has the mainstream and alternative information channels, advanced power system components, including redundant power supplies.
Эффективность разработки месторождений углеводородов определяется коэффициентом извлечения нефти или газа и количеством материальных затрат на освоение недр и их эксплуатацию – рентабельностью проекта. В настоящее время развитие науки и техники позволяет экономически обоснованно разрабатывать залежи с трудноизвлекаемыми запасами за счет применения методов интенсификации притока к скважине, одним из самых распространенных является строительство скважин с горизонтальными профилями. Проводка наклонно направленных и горизонтальных скважин требует применения специального бурового оборудования – роторных управляемых систем (РУС), позволяющих контролировать траекторию ствола скважины в режиме реального времени. На рынке представлен широкий ассортимент оборудования для направленного бурения, в основном зарубежного производства. Для работы с такими системами требуется привлечение высококвалифицированного персонала и часто зарубежных специалистов. В связи с этим разработка программно-аппаратного комплекса удаленного мониторинга и управления траекторией ствола скважины при бурении скважин с использованием РУС является актуальной научно-практической задачей. Предложена теоретико-множественная модель синтеза структуры программно-аппаратного комплекса удаленного мониторинга и управления траекторией ствола скважины при бурении скважин с применением РУС. Такой подход к систематизации создания структур программно-аппаратных комплексов мониторинга и управления позволяет получить качественную информационно-алгоритмическую среду, отвечающую всем требованиям современных стандартов. На основе предложенной модели разработана структура комплекса, включающего набор погружных блоков, реализующих исполнительную и измерительно-управляющую системы, систему передачи информации, систему диспетчеризации. Разработанная структура программно-аппаратного комплекса обладает модульным принципом организации, подразумевает наращивание функциональных возможностей, в том числе введение дополнительных параметров телеметрии, имеет основный и альтернативный каналы передачи информации, развитую систему энергоснабжения компонентов, включая резервные источники питания.
Pumping loss circulation material (LCM) to control drilling fluid losses to the formation is part of the overall solution when taking losses in a drilling operation. Precisely spotting the correct volume of LCM and protecting sensitive directional tools in the BHA has proven to be a considerable challenge. Recently in a critical offshore well in Norway, the 6.5? intermediate section was drilled to 10,446 feet through a soft porous limestone formation. In addition to the chalk formation's propensity for seepage, a pre-existing natural fault was also present. The drilling fluid utilized to drill this section was 8.7 pound per gallon (PPG) paraffin and mineral based mud. Factors key to controlling losses were LCM displacement in precise intervals of the section and timely delivery of the material into the well annulus through a diverter circulation sub. High flow rates and minimal differential pressure at the tool were key to the mud program. Because the RFID enabled diverter circulation sub was capable of being selectively opened and closed using specifically programmed transponders, it did not require a ball seat or mechanical indexing system. This feature coupled with the diverter circulation sub's extra-large total flow area (TFA) and integrated flapper system allowed precise and timely LCM pumping while completely protecting the measurement while drilling (MWD) and rotary steerable (RSS) systems from damaging debris. A total of twenty-nine pills were pumped in the fourteen-day period it took to drill the section. The intermediate section was drilled to 10,446 feet through a soft porous limestone formation. In addition to the chalk formation's propensity for seepage, a pre-existing natural fault was also present. The drilling fluid utilized to drill this section was 8.7 pound per gallon (PPG) paraffin and mineral based mud. Factors key to controlling losses were LCM displacement in precise intervals of the section and timely delivery of the material into the well annulus through a diverter circulation sub. High flow rates and minimal differential pressure at the tool were key to the mud program. Because the RFID enabled diverter circulation sub was capable of being selectively opened and closed using specifically programmed transponders, it did not require a ball seat or mechanical indexing system. This feature coupled with the diverter circulation sub's extra-large total flow area (TFA) and integrated flapper system allowed precise and timely LCM pumping while completely protecting the measurement while drilling (MWD) and rotary steerable (RSS) systems from damaging debris. A total of twenty-nine pills were pumped in the fourteen-day period it took to drill the section. The circulation sub was strategically opened and closed during this pill and LCM pumping program to control losses and allow the operator to drill ahead. By utilizing an RFID enabled circulation sub specifically designed to displace heavy pills and LCM, the operator was able to control losses, maintain proper hydrostatic pressure, and reach total depth (TD).
Abu Roash-D is characterized as a carbonate reservoir in Abu Gharadig field, Western Desert of Egypt. It has a good lateral continuity, contains natural fractures with poor connectivity in addition to formation tightness. To further increase the production from the field, a full development plan for Abu Roash-D carbonate reservoir was initiated with drilling of horizontal wells. The main objectives of drilling such horizontal wells was to develop the tight unconventional reservoirs and increase production by dramatically increasing the contact area with the producing interval, maximizing drainage volume around a well and link the natural fractures network thus, achieving an economically production targets.
The effective placement of sufficient acid volume along the open-hole section of such horizontal wells provides significant challenges in acid diversion due to the high permeability streaks that requires a very effective diversion technique for optimal acid distribution a long the open hole lateral for a successful acid stimulation treatment.
A fiber optic enabled coiled tubing attempts to tackle some of these limitations. This new approach deploys downhole sensors with fiber optic telemetry inside the coiled tubing string provides a real time temperature, pressure and correlated depth measurments. The fiber optic telemetry allows distributed temperature surveys recording for obtaining temperature profiles across the entire wellbore. Monitoring the distributed temperature sensing (DTS) profiles accompined with downhole pressure data interpretation enables real time diagnostic of downhole events between the stimulation stages providing an important aid to further optimize and improve the performance of stimulation treatments.
This paper presents case histories of the first time implementation of horizontal wells in Abu Roash-D tight carbonate reservoir in Egypt's western desert in which fiber optic enabled coiled tubing was utilized to optimize stimulation treatment. The real time monitoring of downhole distributed temperature sensing profiles allowed the identification of both high permeability zones as well as tight zones across the entire openhole lateral. This enabled the operator to take pro-active decision on where to spot diverter or acid, select the best diversion technique and allow for treatment optimization.