Desai, Sameer Faisal (Kuwait Oil Company) | Rane, Nitin M. (Kuwait Oil Company) | Al-Shammari, Baraa S. (Kuwait Oil Company) | Al-Sabea, Salem H. (Kuwait Oil Company) | Al-Naqi, Meqdad (Kuwait Oil Company)
Kuwait Oil Company initiatives for ushering in a new era of digital transformation of its assets to intelligently and optimally manage the Oil and Gas fields were successfully realized with the completion of three pilot projects entitled Kuwait Integrated Digital Fields (KwIDF). This paper discusses major achievements of the Digital Oilfield technology implemented in Burgan KwIDF project and provides an insight on the challenges in operating it.
The Burgan KwIDF pilot successfully transformed GC-1 production asset into a fully instrumented DOF comprising of digital instruments and infrastructure installed at well site and the production facility. Real-time production data is transmitted to a state of the art collaboration center that integrates data continuously with automated workflows for validation, modeling and tuning of well and facility models. Right time decision support information generated from smart visualization tools allow quick actions for production optimization, well and facility management in a collaborative work environment.
There is persistent value realization from KwIDF technology implemented in Burgan field. It has generated substantial cost savings with faster response time in restoring production and reduction in non-productive time. Driven by the digital environment asset production has sustained at target as production gain opportunities are capitalized and losses compensated quickly.
Over the period of time with experience in utilizing the DOF technology it has been observed that the technology sustainment is dependent on the technology providers to a large extent. The main components that require their continuous support are the digital instruments, proprietary software, hardware and related infrastructure. Technical expertise in each domain is necessary for ensuring continuous and smooth operations in the field, wellsite and collaboration centers. Development of an integrated team of domain experts is crucial for successfully managing the DOF operations. Change management initiatives for developing an in house user champion team is mandatory for ensuring sustainment. The important lessons learned and solutions are discussed in detail.
Romero Quishpe, Adriana (YPF Tecnología S.A.) | Silva Alonso, Katherine (YPF S.A.) | Alvarez Claramunt, Juan Ignacio (YPF S.A.) | Barros, Jose Luis (YPF S.A.) | Bizzotto, Pablo (YPF S.A.) | Ferrigno, Eugenio (YPF S.A.) | Martinez, Gustavo (YPF S.A.)
A well is in natural flowing state when its bottom-hole pressure is enough to produce to the surface. Natural flowing well’s production is regulated by using surface restrictions to regulate the production rate in such a way that the overall well performance is a function of several variables. Examples of these variables are tubing size, choke size, wellhead pressure, flow line size, and perforation density. This implies that changing any of these variables will modify well performance. One of the techniques for the analysis of production performsnce is studying the wellhead pressure declination, since, in critical flow conditions, flow is a function of wellhead pressure. From wellhead pressure trends you can identify the behavior of each well and determine some issues, such as: choke erosion due to sand production, choke o tubing paraffin plugging or choke obstruction. In order to achieve an effective real-time monitoring of this type of wells, and in this way reduce the production losses, the challenge was to create online tools that could detect those mentioned issues.
The present work performs the analysis of wellhead pressure curves using data science, with the purpose of predicting real time anomalies that could occur for timely correction. The data correspond to 130 flowing wells from the Loma Campana Field. The study began with a filtering process of the pressure curve, with two specific objectives: first, eliminate atypical values from the time series, and second, smooth the curve in such a way that future predictions can be performed. Next, the Prophet methodology was applied with the purpose of predicting values of the curve. This is based on historicsl values of the time series to predict future values; the trend characteristic of the curve was used to apply this methodology. Then, to identify the anomaly a model was designed based on the declination of the curve. The pressure declination curve is a descending exponential function, so the first and second derivatives indicate the trend (ascending - descending) and curvature (concave or convex) of it. Once these values are available, they are classified according to the anomaly: paraffin, encrustation or obstruction. Finally, the model is being tested in the Loma Campana control room, delivering a probability of occurrence of any anomalies every hour.
Recent advances in data acquisition systems have helped in monitoring wells performance and recording their production parameters like pressure, temperature and valve opening in real time with high frequency. A cost-effective technology to estimate well production rates is Virtual Metering, which integrates real time data and analytical models. This paper presents the methodology of an innovative virtual metering tool and the promising results obtained in real case applications on gas, gas condensate and oil fields.
A Virtual Metering tool has been developed by integrating a commercial software platform and mathematical models (algorithms). The algorithms solve simultaneously dynamic pressure and temperature gradients (VLP) along with the choke equation to find the optimal solution rates that match physical sensor readings. Moreover, the tool manages the communication between real time data and the models enabling a safe storage of the results. Models require a manual calibration at reference dates based on well separator tests or MPFM readings, in a way to match total field production. After calibration, the algorithm is able to run automatically in real-time.
Three implementations are presented about gas, gas and condensate and oil fields, showing the benefits and limitations of virtual meter application. Virtual meter proved to be a valid technology with the potential of even replacing MPFM results, especially in dry gas fields. Where MPFM are installed on each wellhead, virtual meter worked as redundant system and allowed to detect precociously flow meters malfunctioning. The allocation workflow has been modified in order to replace MPFM estimations with virtual meter ones. For oil fields with variable production parameters, the tool has provided reliable independent rate estimation by combining VLP and choke calculator in a unique optimization tool. The real time flow rate can be used as a basis for pro-rata allocation of fiscal production in the framework of a Production Data Management System software. Additional features of the tool are the following: a real-time input for pressure and rate transient analysis and a workflow for real-time well drawdown estimation of gas wells, which makes use of automatic p/z reservoir model update to estimate reservoir pressure. Moreover, this tool had a significant impact on production monitoring, improved the effectiveness of production optimization actions and the quality of history match of reservoir 3D model.
This paper contains a novel approach of a reliable and robust virtual metering tool that can be flexibly applied to gas and oil fields through a unique optimization algorithm, which is able to combine information coming from production network and from the reservoir side. It gives benefit to company workflows by feeding external reservoir analysis applications that would not be possible without virtual meter results and uses the results of external applications for validation purpose.
A long-term suspended subsea exploration well within a producing gas reservoir needed to be decommissioned after 21 years. During a pre-decommissioning diving campaign, bubbles confirmed as reservoir gas were observed to be percolating from the well bore through a hard silt / cement debris plug inside the wellhead. A pressure study established that the reservoir may have re-charged to 2,200 psi. An alternative pressure controlled well re-entry method was required to safely re-enter, tie-back the well to surface with 16-in. high pressure riser, install BOP while preventing gas from reaching the rig floor from seabed. Two existing cement plugs would then be drilled out under controlled conditions due to the potential for high-pressure gas beneath the plugs. Casing integrity evaluation and cement bond logging would be carried out to establish the path of gas ingress into the wellbore. Remedial work would be conducted, and permanent abandonment barriers installed in the well. Casings and wellheads would then be recovered from a depth below the seabed.
A customized managed pressure drilling (MPD) system was designed using a rotating control device (RCD) and modified drilling chokes. A pioneering plan was developed to meet the specific well re-entry requirements of the percolating suspended well to account for the potential for virgin reservoir pressure at seabed and the wellhead silt plug preventing deployment of BOP test tools. A hazard and operability study (HAZOP) was conducted with key personnel, which supported development of well-specific operating procedures and decision matrices. Successful deployment included MPD system calibration, well behavior fingerprinting, and training of rig personnel at the well site.
The combination of experienced personnel, innovative MPD equipment, specific procedures, team interactions and risk analyses were key to safely completing this well re-entry and decommissioning scope. The strategy enabled drilling out of two cement plugs with potential high-pressure gas trapped beneath them. Both cement plugs, 356ft and 669ft long, were drilled without any well-control or plugged-choke events. Throughout the process, the well was monitored using MPD equipment, which included an RCD on top of rig's BOP, modular drilling chokes and multiple pressure gauges and sensors installed at critical points. Additionally, temporary modifications were made to the rig and new lines of communication between the rig crew and the MPD team were established to ensure all pressures were correctly interpreted and the decision matrix was correctly applied. An effective close partnership developed between the equipment service provider, well operator and drilling contractor was a key enabler to deliver this very challenging novel implementation of MPD technology within eight weeks. The MPD approach was estimated to have saved 9 days of rig time, when compared to alternative coiled tubing-based solutions.
This paper describes the first MPD-assisted well re-entry for well decommissioning in the UK North Sea sector. The novel application of existing technology can help operators to cost effectively re-enter and decommission troublesome legacy wells without harm to people, environment or assets. This new approach resulted in the safe unconventional re-entry and decommissioning of a potentially live gas well.
Africa (Sub-Sahara) Sahara Group discovered hydrocarbons in three wells drilled in Block OPL 274, located onshore in Nigeria's Edo State. Olugei-1 was drilled to a measured depth of 4537 m and encountered five hydrocarbon zones, with 33 m of net pay. Oki-Oziengbe South 4 was drilled to a measured depth of 3816 m and encountered 64.3 m of net pay in 13 hydrocarbon-bearing zones. Oki-Oziengbe South 5 was drilled to a measured depth of 3923 m and encountered 91 m of net pay in 19 reservoirs. Sahara Group (100%) is the operator. Asia Pacific Sino Gas & Energy Holdings (SGE) flowed gas (coalbed methane) from its first horizontal well in the Linxing production sharing contract (PSC) in China's Shanxi province.
Africa (Sub-Sahara) Eni started production from the West Hub development project's Mpungi field in Block 15/06 offshore Angola. The startup follows the project's first oil from the Sangos field in November 2014 and the Cinguvu field last April. Mpungi will ramp up West Hub oil production to 100,000 B/D in the first quarter from a previous level of 60,000 B/D. The project also includes the future development of the Mpungi North, Ochigufu, and Vandumbu fields. Eni is the block operator with a 36.84% stake. Sonangol (36.84%) and SSI Fifteen (26.32%) hold the other stakes.
Content of PetroWiki is intended for personal use only and to supplement, not replace, engineering judgment. SPE disclaims any and all liability for your use of such content. The equation is used in the design of chokes and explains the manner in which pressure in the body in the body of the choke, downstream of the first pressure drop, is lower than the eventual recovery pressure at the end of the choke.
The one-circulation method is a well-control procedure. To implement this method certain guidelines must be followed to ensure a safe kick-killing exercise. Although the procedure is relatively simple, its mastery demands basic knowledge of the practical steps taken during the process. A kill sheet is normally used during conventional operations. It contains prerecorded data, formulas for the various calculations, and a graph--or other means--for determining the required pressures on the drillpipe as the kill mud is pumped.