Directional Drilling (DD) achieves higher well production and improves accessibility of oil reservoirs in complex locations. Quad Motor drilling heads was recently proposed to achieve better steering control of the drilling operation and higher dogleg severity. The current state of the art in DD is the Rotary Steerable System (RSS), where steering actuators displace the centerline of the drilling system away from the centerline of the hole by a controllable amount of eccentricity. The drilling bit is powered by the rotation of the drilling string. However, in the quad motor drilling head, four drilling bits are independently controlled by 4 downhole motors. This paper proposes a real time control and optimization of the quad bit directional drilling system. The control commands include the angular velocity and torque of each of the 4 motors. The control is updated at regular distance intervals. The optimization procedure determines the drilling parameters to minimize the drilling time and the deviation from the planned trajectory.

Rubiales and Quifa fields are major heavy oilfields (oil gravity ranges from 11.3 to 14.4 °API) in Colombia with a current oil production of more than 264 MSTB and an oil viscosity range from 370 to 730 cP. Horizontal well technology used to drill through unconsolidated sandstones with an active and strong aquifer, under primary depletion, has been used to develop this field. Since 2006, 1,019 horizontal producer wells have been completed using slotted liners (conventional completion) because of the low cost and effectiveness in controlling the coarse-grained sand formation and low fines production. The high water production rate from the beginning of the operation in the horizontal wells is the primary problem in these fields because of the high cost of produced water treatment and other factors. In formations in which high permeability, high oil viscosity, and strong aquifers are combined, early water influx can result. Water production is predictably associated with the oil production; however, one of the major challenges is to delay the water production for as long as possible. Currently, a large number of wells are closed in that have reached economic limits, primarily caused by high water cuts. An autonomous inflow control device (AICD) was placed in each screen joint to balance the production influx profile across the entire lateral length and to compensate for the permeability variation and therefore the productivity of each zone. In late 2012, a new technology project was designed and implemented as a pilot to help address the described issues in horizontal wells. AICDs would be used to maintain equilibrium of produced fluids along the horizontal section of the well, ultimately delaying water coning. After the first pilot is completed, a technical analysis could be conducted, based on the results obtained, and, if possible, the AICD technology could be implemented in additional prospect wells. The AICD pilot was implemented in geological conditions more adverse than wells previously completed with conventional completions and still other wells previously completed with passive but non-autonomous inflow control device (ICD) completions; the pilot will be evaluated with horizontal wells of the area. The main purpose of this paper is to provide details about the selection process, design, and evaluation results for the use of the AICDs in horizontal wells in both heavy oil fields.

Extended Reach Drilling (ERD) wells can be extremely long and technically challenging from drilling through completions, clean up, stimulation and production optimization. This paper will focus on the key challenges associated with ERD well completion, real-time clean up, production monitoring and optimization and will present an advanced intelligent solution enabled by new technologies to handle these complex challenges. As the fields become more mature, there is an increasing requirement for real time flow profile understanding and interventions to correct unwanted flow profile anomalies such as water production, gas breakthrough, etc. to have better production and reservoir management. By combining real-time data monitoring and active control with optimal zonal isolation along the wellbore has been proven to be one of the most efficient and effective completion strategies in the industry for the abovementioned requirements. The operator can proactively manage production, eliminate or reduce interventions and associated production downtime, well costs and risks. However, getting the invention less permanent intelligent completions to the Total Depth (TD) of ERD wells is one of the major challenges and hence very long horizontal ERD wells are typically completed partially leaving out stretches of reservoir section unmonitored and uncontrolled. Also, conventional intelligent completions have clear limitations on number of flow control valves and sensors that can be deployed in a well, mainly limited by the maximum number of control lines, which can be deployed with the completion. The limitation comes from the feedthrough port limitation of critical completion tools such as tubing hanger, production packer etc. and also from the completion deployment challenges faced with increasing number of control lines. This limits the ability to have an optimal segmentation along the wellbore in many cases. Another important challenge that our industry faces is in effectively using real-time monitoring data to make informed decisions and take required actions efficiently. Traditionally the whole process of data gathering from down hole tools to decision making and taking reasonable action is long ranging from months to years and requires multi-disciplinary expertise. As a result the well controllability, reservoir management and hence production optimization are compromised due to technology solutions limitation. New all electrical solution with reliable downhole wet connects and integrated answer product software for data management and analysis of real-time data presented here is a key intelligent end to end solution. This paper gives details of this new generation technology solution that enables above mentioned challenges.

There is a critical need for robust and reliable downhole power generation and storage technologies in order to push the boundaries of downhole sensing and control. Downhole power harvesting is an enabling technology for a wide range of future production systems and applications including self-powered downhole monitoring, downhole robotics, and wireless intelligent completions. This paper provides an analysis of available ambient energy sources in the downhole environment, and various energy harvesting techniques that can be employed to provide a reliable solution. Advantages and limitations of conventional technique like turbine are compared to advanced energy harvesting technologies. The power requirements and technical challenges related to different downhole applications have also been addressed. We have also presented a single-phase flow energy harvesting system based on vortex-induced vibrations by employing a bluff body in fluid flow. A laboratory experimental setup was developed that consists of a 2” flow loop, piezoelectric energy harvester, power management module, and capacitor storage. Computational fluid dynamics (CFD) simulations of the vortex-induced flow-vibrations for our setup have been presented. The generated vortex shedding frequencies and generated power in the flow loop is very low, which suggests requirement of a reliable rechargeable battery. Finally, recommendations are made for improvement and achieving the goal of practical implementation of downhole power harvesting.

E&P Operators are facing challenges with the on-going development of brown fields and the increasing need for accurate wellbore placement and geosteering during infill drilling. This is driven by business plans that involve large in fill well drilling program. The planning and execution of these in fill wells will involve the drilling of highly deviated, horizontal and extended reach wells. Good use has been made historically of the geosteering services provided by contractors in order to support drilling programs. This paper investigate the process of establishing an Integrated Geosteering Environment (IGE) that would enable efficient collaboration between reservoir geologist, petrophysicist, operational geologists, reservoir engineers and drillers engaged in field development. This environment makes use of a real time data to enable the drilling team to reduce risk and reservoir uncertainty while maximizing wellbore contact with the zone of interest. This will translate into reduced drilling time, better well placement and an increase in capital efficiency. The paper primarily focuses on the establishment of the IGE that will enable the development of workflows to optimize the placement of horizontal wellbore to achieve the business objective. The workflows cover predrill planning, drilling execution including 24/7 real time monitoring to steer the well, post well evaluation and update the reservoir model. This is enabled by real time data acquired while drilling along with modelling visualization tools. Transforming from the current working environment into an Integrated Geosteering Environment combined with a real time Drilling Environment enables effective decision making and increased business agility towards achieving Operator business objectives, increasing oil recovery and sustaining the production capacity of brownfields. There are several papers in the past addressing collaborative work environment or shared earth model. This paper discusses real time integrated workflow between sub-surface and drilling domains from a geosteering perspective.

Advances in drilling and well construction technologies have enabled extended-reach horizontal and multilateral wells to increase reservoir contact and improve recovery. Completion systems with passive inflow control devices (ICD) or intelligent wells are used to optimize and control inflow from the compartments or laterals. ICD completions are passive systems with torturous paths or orifices designed to choke back inflow from dominant zones and equalize influx along the wellbore. ICDs combined with openhole packers provide very fine compartmentalization of the open hole and it is common to have completions with 40 inflow compartments in some extended-reach wells. ICD completions require well intervention to close zones with high water or gas. Intelligent completions, on the other hand, have downhole valves that can be remotely operated from surface. The requirement for downhole control lines and penetrations at the wellhead and packers has limited the number of downhole valves to a maximum of six in a well. This limitation excludes a significant number of applications where greater compartmentalization can yield superior well performance. The industry has recently developed innovative completion systems that increase the number of surface-controlled downhole valves while minimizing the number of downhole lines. These technologies improve completion design while overcoming limitations like the number of control lines, feedthrough ports on packers and wellhead. Saudi Aramco has recently installed an all-electric intelligent completion with 8 downhole active flow-control devices (AFCD) controlled via a single downhole control line. This installation is currently the world record for the highest number of inflow control valves installed for an intelligent completion. This paper presents details of technology development, evaluation, completion design, installation and in-well testing of the all-electric intelligent completion system in a multilateral well. The paper presents the novel completion design with redundancies, system components, advantages of the chosen technologies and the completion method. The section about the planning phase of installation highlights steps taken to ensure successful execution of the job while minimizing operational risks associated with the deployment of the new technology. Finally, the execution phase of the installation is presented with special emphasis on procedures and actions during installation to improve operational efficiency and minimize health and safety (HSE) risks. Thorough design, planning and execution of the job yielded the successful installation of an advanced and complex intelligent completion system in an efficient and safe manner. All-electric intelligent completion systems capable of controlling multiple downhole valves are anticipated to increase well life and recovery through improved downhole monitoring and control. This system can control as many as 27 AFCDs on a single electric control line.

Horizontal wells have provided operators a way to maximize reservoir contact, improve sweep efficiency and well productivity. Conventionally completed horizontal wells present a high risk of gas cusping and water coning that can significantly affect the well's effectiveness. Preventing early unwanted fluid breakthrough is key to the well's success, hence it is critical that an even production influx profile along the entire wellbore is achieved. The production profile along the wellbore is affected by various parameters, including: heterogeneity with respect to the permeability and reservoir pressure along the wellbore, the presence of fractures, and frictional effects. Inflow control devices (ICDs) were developed to delay gas/water breakthrough, maximize sweep, and reduce — even potentially eliminate — future well intervention. ICDs have become a mainstream completion tool in Saudi Arabia. With each ICD completion deployment, a better understanding is gained with respect to deployment and installation of the lower completion, as well as a greater insight to how to achieve optimum reservoir management. Analysis gained from the previous wells has helped capture a substantial amount of best practices and lessons learned. This paper intends to capture the lessons learned after more than 10 years of deployment of inflow control completions in Saudi Arabia. The main topics that are to be discussed are: ICD types, the optimum operating envelope, and new technological advancements Optimum ICD design approach Open hole packers Deployment systems Best operational practices and their potential impact This paper provides a guideline for designing a well with ICD completions, and explains how the advancement in technology impacts cost, time and reservoir management.

Horizontal well is an important technology to enhance oil recovery for both old oilfield and new oilfield. Horizontal well have four characteristics: large drainable area; small producing pressure drop; high fluid productivity index and long water free production period ( Joshi S. D. 1991 ) compared with vertical well. The contact pattern between horizontal section and the layer is line contact, and the pressure drop around the horizontal section is a linear distribution. The pressure drop near the bottom of the horizontal well will be far less than that of the vertical well if the same fluid is produced. Therefore, horizontal well can inhibit bottom water coning more effectively. The critical production of horizontal well is greater than that of vertical well for bottom water reservoir(Chaperon 1986, Papatzacos P. et al. 1991 ). But horizontal well may form water cresting. The reserves controlled by the horizontal section and volume swept by the bottom water is far larger than that of the vertical well, so it can increase the cumulative water free production. Therefore, comparing with vertical well, horizontal well can prolong water breakthrough time and improve the ultimate recovery (Permadi P et al. 1995, Wibowo W et al. 2004 ), which is one of the reasons for horizontal well technology used in bottom water reservoir widely at home and abroad. But with the oilfield development, horizontal well has also exposed some questions gradually. Vertical well has a long water cut production period, but water cut of the horizontal well increase dramatically after water breakthrough, which affected horizontal well development seriously (Souza A L S. 1997).

In order to maximize oil production, it is desirable to have a balanced influx of oil from the entire completion. Non-uniform production rates from each zone along the completion may not be evident early in the well’s production life, but they can become problematic when water and gas break through. If water and gas break through in select zones, they will produce at higher rates than the oil, which in turn will impede oil production rates from the remaining zones. Formation permeability variations or toe-to-heel friction loss can cause flow rate differences between zones, and in a heavy-oil well, these variations may be even greater. Viscous fluids experience larger frictional losses both in the formation and the wellbore flow conduit; thus, when low viscosity water or gas breaks through, the flow from a high water or gas cut zone can quickly dominate the flow from the well. Inflow Control Devices (ICDs) have been developed to balance the influx of oil by creating additional back-pressure in the zones that produce at higher rates. Using ICDs can delay water or gas breakthrough, but once unwanted fluids break through, conventional passive ICDs are not able to maintain the balanced flow. This paper discusses a new ICD, an autonomous inflow control device (AICD), which performs similar to a passive ICD during oil production and can be used to balance reservoir influx. Unlike passive ICDs, when unwanted fluids (water, gas) flow through the AICD, they take a different path than oil, and a much higher pressure drop is created. This behavior can be used to restrict the flow of unwanted fluids when they break through in a zone, allowing the oil production from other zones in a well to continue at the maximum rate. Simulations are presented that will compare a stand-alone screen completion to a completion with passive ICDs, to a completion with an autonomous ICD. The simulation results will show a clear distinction in each type of completion, and it will highlight the benefits that are provided with the ICD and the even greater benefits derived from use of the AICD, both onshore and offshore.

Almost a decade has passed since Saudi Aramco implemented its first intelligent completion in a remote area field. Nowadays, the field is the crown jewel of intelligent well completions worldwide, with a large number of inflow control valves (ICVs), a permanent downhole monitoring system (PDHMS), and multiphase flow meters (MPFMs). This paper summarizes the lessons learned from the assessment and optimization of hundreds of laterals in the field. It also shows how proper ICV utilization leads to production optimization throughout the field. It sheds light on the best practices that helped to realize the full potential of those installations. Finally, the paper ends with recommendations for the way forward and conclusions. Examples will be discussed in detail to show clearly the benefits and results that could be harvested from the use of intelligent completions. These examples will show some of the benefits that include the revival of dead laterals, controlling undesired fluid breakthrough, and managing sweep efficiency.

Proven to maximize hydrocarbon production or well injectivity, horizontal multilateral completions have witnessed growth both in number and complexity over the years. These well types brought challenges with respect to well accessibility for rigless well intervention, and the ability to access these wells has been developed using coiled tubing (CT) to enable operations, such as reservoir stimulation, to be carried out. One of the main challenges is to identify and access each lateral, to be able to perform the stimulation to maximize well production. This challenge has been encountered in Saudi Arabian multilateral wells, which are drilled in a carbonate reservoir with an open hole (OH) completion and where the laterals are typically left with a high formation damage (skin effect) after drilling, thus requiring stimulation to improve their performance. At present there is no single technique for lateral identification without tagging TD. In this paper we describe how a combination of multilateral tool (MLT) along with CT downhole measurement system is used to locate and access laterals, selectively acquiring a gamma ray profile across each of the laterals, then optimizing the stimulation operation using distributed temperature survey (DTS) measurements. This paper discusses the planning, execution and evaluation of the results in a stimulation job performed on an open hole multilateral water injector employing a CT with fiber optics that enables a real-time downhole measurement tool (pressure, temperature, casing collar locator, gamma ray) and MLT. The results highlight the effectiveness of the technique in maximizing the wells performance.

The technique of geosteering has been widely adopted in the petroleum industry for proper wellbore positioning. The benefits of geosteering have become more pronounced as drilling environments have become more complex. Geosteering-related technologies, such as downhole information gathering tools, real-time data transmission and data-analysis applications, have been continuously and significantly improved to support geosteering decisions. However, the full value of these advancements has yet to be realized. Due to uncertainties in predrilled geological models, information gathered while drilling is applied in making real-time reservoir navigation decisions. To achieve an optimal result requires a series of high-quality decisions regarding well trajectory adjustment. Interestingly, geosteering-related literature does not demonstrate that the industry has applied a logically consistent approach for making geosteering decisions. Common practice as described in the literature does not clearly and quantitatively state measurable objectives, key underlying uncertainties, or relevance between underlying uncertainties and real-time information. Furthermore, it is unclear how a specific geosteering decision is being reached. Lacking of a systematic and transparent framework for supporting geosteering decisions, the current approach is unlikely to result in optimal decisions for placing the well in the best possible location.

Reservoir simulation is one of the main if not the most important tool reservoir engineers use to forecast a reservoir performance. Nevertheless, developing and operating a reservoir simulator tool in the first place can be an arduous task that requires a set of highly skilled individuals in science, advanced mathematics, programing, and reservoir engineering and powerful computational models ( Ertekin, et al., 2001 ). The reliability of a reservoir simulator depends on the availability and the quality of the reservoir properties. These properties are obtained from open-hole logs, core studies and well testing analysis which can sometimes be prohibitively cost intensive. Another important component of the overall process affecting the reservoir performance is the multilateral well configuration. Achieving the right design of a multilateral well configuration is a complex problem due to the vast possibilities of well forms that need to be evaluated. In light of the above, this paper demonstrates the development and the application of a set of integrated artificial expert systems in the area of forecasting, reservoir evaluation and multilateral well design. The applied method is implemented to volumetric single phase gas reservoirs with a variety of rock and fluid properties spanning tight to conventional sands. The developed approach delivers a proxy to the conventional numerical simulator for predicting reservoir performance, an expert system for estimating reservoir properties from rate decline data, and an expert system for recommending multilateral well design parameters for a target recovery profile. Furthermore, graphical user interfaces (GUIs) in conjunction with the expert systems structured are developed and assembled together for standalone installation. These GUIs allow the engineer to edit and input data, produce results numerically and graphically, compare results with a commercial numerical simulator, and generate an interactive 3-D visualization of the multilateral well. It is expected that the developed expert systems will immensely reduce time requirements and effectively enhance the overall decision-making process. However it is emphasized that this paper is not suggesting the replacement of existing and well established procedures, protocols and know-how with the developed expert systems, but rather applying them as auxiliary, pre- screening or complimentary systems where and when applicable to ease of the computational overload, deliver a solution to the inverse-looking problems and enhance the overall decision-making process.

Optimizing production and understanding inflow from long horizontal wells in tight chalk reservoirs has traditionally been difficult. The horizontal sections of these wells have been typically segmented into four to eighteen zones, driven by completion, stimulation and reservoir management requirements. Surface controlled sliding side doors have been used in a number of wells to control the zones for production optimisation, but permanent down hole monitoring of each zone had not been undertaken in the Danish sector so far. The subject of this paper is the installation and application of zonal pressure gauges and distributed temperature sensing in a recently drilled long horizontal oil producer in the Danish sector of the North Sea. Despite a very challenging trajectory and reservoir pressure variations along the horizontal section the well was drilled to 24,000 ft measured depth and equipped with permanent downhole monitoring and control capabilities. The horizontal reservoir section was segmented into five zones. In each zone a surface-controlled sliding side-door and a pressure and temperature gauge were installed. A fibre-optic cable for distributed temperature sensing (DTS) along the upper four zones to a depth of around 15,500 ft was installed as well. The upper four zones also contained an extra coiled-tubing operated sliding side door for restimulation purposes. After completing the well each zone was matrix acid stimulated. Stimulation monitoring with DTS allowed quantification of zonal acid coverage and identification of the scope for re-stimulation. During initial production of the well the pressure and temperature gauges in each of the zones proved valuable for start-up operations. Cross-flow between zones was identified and this knowledge was used for improved management of commingled zonal production. This paper describes how temperature and pressure data from each zone has been used for well production optimisation, in sometimes unexpected ways. The combination of being able to react without intervention using the real-time data has proven to be critically important and supported more efficient operations.