This paper discusses the first multilateral well with a Level-4 junction combined with an inflow-control device (ICD) planned, designed, and drilled in the Upper Burgan reservoir of Raudhatain field, north Kuwait. Several designs for autonomous inflow-control devices (AICDs) are available. The comparative properties and abilities of these designs are the focus of this paper. As part of a project that involves the use of four artificial islands to drill and complete more than 300 extended-reach-drilling (ERD) wells in a giant offshore oil field, several completion designs have been piloted for brownfield development.
Multilateral wells with smart completions controlled by different flow-control technologies offer great operational flexibility, with each lateral able to be operated and optimized independently. The use of intelligent software is on the rise in the industry and it is changing how engineers approach problems. A series of articles explores the potential benefits and limitations of this emerging area of data science. This paper discusses the first multilateral well with a Level-4 junction combined with an inflow-control device (ICD) planned, designed, and drilled in the Upper Burgan reservoir of Raudhatain field, north Kuwait.
The operator piloted a new well-completion design combining inflow-control valves (ICVs) in the shallow reservoir and inflow-control devices (ICDs) in the deeper reservoir, both deployed in a water-injector well for the first time in the company’s experience. This paper discusses the first deployment of an ICD system combined with an OBC system for a workover operation in a mature producer well in the Kingdom of Saudi Arabia. With the objective of increasing its production to 4.0 million BOPD, the Kuwait Oil Company (KOC) is developing its fields with optimum technology solutions. This paper discusses the first multilateral well with a Level-4 junction combined with an inflow-control device (ICD) planned, designed, and drilled in the Upper Burgan reservoir of Raudhatain field, north Kuwait.
The basic objective of this course is to introduce the overview and concept of production optimisation, using nodal analysis as a tool in production optimisation and enhancement. The participants are exposed to the analysis of various elements that help in production system starting from reservoir to surface processing facilities and their effect on the performance of the total production system. Depth conversion of time interpretations is a basic skill set for interpreters. There is no single methodology that is optimal for all cases. Next, appropriate depth methods will be presented. Depth imaging should be considered an integral component of interpretation. If the results derived from depth imaging are intended to mitigate risk, the interpreter must actively guide the process.
Houston-based Surge Energy drilled the Medusa Unit C 28-09 3AH well in the Midland Basin to a TMD of 24,592 ft, with a total horizontal displacement of 17,935 ft, or 3.4 miles. Oil companies generate an enormous amount of data but are reluctant to share it. But more sharing of information may be required in the future to keep up with a rapidly changing energy landscape. The discovery is world’s third-largest natural gas discovery in the past 2 years. A drilling team has focused on increasing lateral lengths in the Marcellus Shale.
This paper describes a new approach to evaluating the effectiveness of the rotary-steerable-system (RSS) steering mechanism on wellbore tortuosity in horizontal wells. This paper demonstrates a work flow to determine optimal lateral lengths and trajectories in the Midland Basin by studying the effect of the lateral length and trajectory on well production. With the arrival and development of rotary steerable systems in the late 1990s, the industry thought that drilling a perfectly smooth and controlled trajectory would not be an issue. Range Resources' drilling head talks about how the company went from drilling the shortest laterals in the Marcellus to the longest and why. The Apollonia tight-gas chalk play is located in the Abu Gharadig Basin in the Western Desert of Egypt.
Ali Khan, Farhan (Weatherford) | Antonio Sierra, Tomas (Weatherford) | Gabriel Imbrea, Robert (Weatherford) | Robin Edwards, Michael (Weatherford) | Al-Rushoud, Ali (Kuwait Oil Company) | Al-Abdulhadi, Fahad (Kuwait Oil Company) | Shehab, Abdulaziz (Kuwait Oil Company) | Al-Ajeel, Fatemah (Kuwait Oil Company)
Project deliverables included gravel foundation preparation, concrete foundation installation, equipment reception and installation of conventional beam pumping units at 660 production wells in a remote field in Kuwait with a deadline of six months from equipment arrival. Equipment shipments schedules were sequential and therefore an execution strategy was required to successfully meet the project deadline. This paper describes the field operations strategy devised and adopted to successfully meet the deadline. A temporary operations base was set up at the remote field for coordination, equipment reception, inspection, consolidation, pre-assembly and dispatches. Operations were divided into six parallel processes as follows: 1. Equipment logistics 2. Gravel foundation preparations 3. Concrete foundation installations 4. Unit Pre-assembly 5. Pre-assembled units dispatches 6. Final unit installations Daily output targets were set for each process prior to the commencement of operations.
Gorgi, Sam (Halliburton) | Joya, Jose Francisco (Halliburton) | Al-Ebrahim, Ahmed (Kuwait Oil Company) | Rashed Al-Othman, Mohamad (Kuwait Oil Company) | Abdullah Al-Dousari, Mohamad (Kuwait Oil Company) | Mohamad Ahmed, Abdulsamad (Kuwait Oil Company) | Omar Hassan, Mohamad (Kuwait Oil Company) | Mohammad Al-Mansour, Jassim (Kuwait Oil Company) | Elsayed, Abdou (Kuwait Oil Company) | Alboueshi, Alaa Eldin (Halliburton) | Allam, Ahmed (Halliburton) | Robles, Fernando (Halliburton)
This paper presents a case history application of real-time fiber-optic technology in the Bahrah oil field, onshore Kuwait. A primary challenge during openhole swellable packer completion operations with multistage fracturing is understanding the number of fractures induced in the formation, particularly in heterogeneous formations where the fracture pressure energy will be distributed along the openhole section. Therefore, fiber-optic technology was selected for the Bahrah project. The application consists in diagnosing a tight carbonate reservoir after multistage acid fracturing and milling the baffles of a production sleeve completion to obtain a well production profile. This technology consists of a fiber-optic cable and a modular sensing bottomhole assembly (BHA). The fiber-optic cable provides distributed temperature sensing (DTS), whereas the BHA is used to monitor pressure, temperature, and the casing collar locator (CCL) in real time.
The usual procedure when using conventional coiled tubing (CT) to stimulate a carbonate openhole section is to treat all pay zones with acid and diverter, which increases both operation time and operational costs. In addition, inadequate control of the treatment placement will often result in ineffective stimulation. When using the fiber-optic technology, monitoring is performed by analyzing the distributed temperature profiles both before and after stimulation; the BHA helps ensure that the optimum pressure is maintained and that the fluid is placed accurately through depth correlation sensors. All components of this intervention are performed in a single trip, which reduces both costs and operation time.
This paper presents an application that uses the modular sensing BHA to improve the performance of milling balls and baffles in the horizontal production sleeve completion. Afterward, DTS is used to diagnose the reservoir performance after multistage acid fracturing to identify fracture initiation points (FIPs). This assists in design optimization, provides better understanding of formation properties, and helps determine the flow rate distribution of each stage across the entire lateral. Another application uses DTS to obtain the production profile of a 3,286-ft horizontal section while flowing back the well through an electrical submersible pump (ESP). The paper presents the methodology and results of these applications.
Using this technology in the petroleum industry helps reduce operation time by up to 50% as a result of performing various CT activities in a single run. This eliminates the need for additional logging or slickline runs using the same BHA, after performing the milling operation to collect DTS data for FIPs and flow rate distribution analysis in the same run. It also reduces costs by enabling real-time decision-making capabilities and effective stimulation.
Anis, Apollinaris Stefanus Leo (Schlumberger) | Syarif, Zilman (Saka Indonesia Pangkah Limited) | Setiawan, Ade Surya (Schlumberger) | Hidayat, Azalea (Saka Indonesia Pangkah Limited) | Murtani, Anom Seto (Saka Indonesia Pangkah Limited)
Ujung Pangkah Field which located at offshore East Java Indonesia, is known for its challenging nature from geological, reservoir and drilling perspectives. Drilling experiences in this area shows severe wellbore instability in overburden shale and in fractured carbonate reservoir. Hydrocarbon production directly exacerbate drilling problems and production issues that were not expected came earlier than predicted, for example early water breakthrough. At least two or three operators facing similar severe wellbore instability problems in the area.
Due to the complexity of subsurface systems and coupled interactions between depletion and stresses, the present-day stress state in Ujung Pangkah Field which have undergone production will be different from the pre-production stress state. Therefore, a comprehensive analysis will require numerical modelling involving coupling of 3D geomechanical model with fluid flow during production operations from dynamic model. Present-day stress state is subsequently used for wellbore stability analysis of planned development wells in Ujung Pangkah Field. Investigation of the behavior of natural fractured reservoir during depletion and its impact to reservoir management is also attempted. Two-way coupling of geomechanic and dynamic models were conducted whereby porosity and permeability update due to production were simulated based on uniaxial pore volume compressibility tests. Hence, porosity and permeability of fractures are not considered static anymore but dynamic due to stresses changes and production.
The result of coupled simulation is able to reduce wellbore instabilities significantly in the planned well. The stable mud weight windows for planned wells are extracted from the model. The stable mud weight window in the reservoir interval is narrow to no stable drilling window in all the planned wells due to depletion. In general, the preferred direction to drill, requiring lowest mud weights, is in the direction of minimum horizontal stress which in this case is Northwest-Southeast (NW-SE). However, it was found that azimuthal dependency of mud weight is insignificant due to low horizontal stress anisotropy.
Reservoir compaction and sea-bed subsidence were also calculated using the outputs from the model. The result is useful for completion and platform integrity.