Critical drawdown pressure for sand onset and its accuracy with change in water cut is a continuous area of study. The numerous parameters like grain cementation, viscosity of fluids, actual physics of sand production with fluids leads to a lot of uncertainty. In practical terms, it has been observed that these mechanisms lead to reduction in Uniaxial Compressive Strength of rocks. The objective of this paper is to present a novel method that not only helps on understanding the effect of water production on sand failure but to further predict the volumetric expected sand production up until a certain tolerable error.
A sand prone field within Malaysian region was identified and core tests were done to evaluate UCS and other rock strength parameters at different saturation of water to simulate the effect of water on rock strength. CDP evaluations were done and the values were calibrated with actual field data to have an accurate understanding of CDP values at different water cuts. Lastly, with the findings from field production data, limit was pushed further to develop a novel method to predict the volumetric sand production.
The proposed novel method has helped not only in understanding the effect of water production on sand failure but also on the amount of sand to be produced under different drawdown pressures with a reasonable accuracy. These results proved very useful in implementing Company's Holistic Sand Management strategy. The integration of this method with water cut predictions from reservoir simulation models helped the team to quantify the continue increasing sand production due to water cut increase. Company is replicating similar workflow in other sand prone fields for an effective sand management.
The approach is very novel as the theoretical modelling work has been effectively calibrated using real field data. This method has provided a high degree of confidence in estimating the amount of sand to be produced under different production conditions.
Authors consider this as a breakthrough in field of holistic sand management and very useful workflow for all other operators to emulate.
Amsidom, Amirul Adha (PETRONAS) | Ghonim, Elsayed Ouda (PETRONAS) | Alexander, Euan (PETRONAS) | Kuswanto, Kuswanto (PETRONAS) | Abdullaev, Bakhtiyor (PETRONAS) | Hassan, Hani Sufia (PETRONAS) | Ishak, M Faizatulizudin (PETRONAS) | Rajah, Benny (PETRONAS) | Gunasegaran, Puvethra Nair (PETRONAS) | Ayad, Kamal (Cornerstone for Business Development) | Madon, Bahrom (PETRONAS) | Hamzah, M Amir Shah (PETRONAS) | Zamanuri, Kautsar (PETRONAS)
About 80% of brownfields in Malaysia use Gas Lift as the artificial lift method. Though it is widely used, the operators are facing numerous challenges which include shortages in gas lift source and compressor reliability issues. Consequently fields’ productivity is impacted and results in higher operating expenditure. A case of change from Gas Lift to ESP was studied however due to high rig costs many of these the projects are uneconomic. Given this is the case PETRONAS had been researching the use of high speed slim, power- cable deployed ESPs for installation inside 2- 7/8" and 3-1/2" tubing (TTESP-CD). The challenge was to develop a deployment method using intervention techniques to comply with process safety requirements and installation over a live well without any workover rig. The associated technologies to enable deployment and operation of the ESP were identified, modified, developed and qualified as required in order to meet API 6A, API 14A and ISO 14310.
In order to meet the project objectives and derisk technical uncertainties, an onshore test run and offshore pilot were planned. These ensured the design requirements of the key deployment technologies met relevant API and ISO standards; 1) wellhead adapter for cable exit and load handling 2) the anti-rotation anchor packer and 3) the insert safety valve, 4) wireline unit, 5) pressure control equipment. Each of the technologies developed or modified are key components of the deployment technique. Through the onshore testing, the deployment procedure and running equipment were improvised to fit the offshore pilot installation.
The deployment of the TTESP-CD system offshore was a success; the ESP was installed within 3-1/2" 9.2ppf tubing to a depth of 1752ft over a live well using the modified deployment package. The actual ESP deployment took around 5days including rig up/down of the deployment package. Running the ESP to depth only took around 8hrs including setting the insert safety valve. Major time consuming events were assembling the ESP, cable space- out, cable termination/splice, landing hanger and cleaning out the electrical connections. Looking forward; this is a technology PETRONAS see great value in for Malaysian and international assets. Currently there are plans for four more installations in 2018 and a minimum of five installations in 2019.
The PETRONAS led team have overcome challenges the industry has faced for many years with regards to this type of ESP deployment by investing in R&D and committing resources. By developing this technology PETRONAS and its technology providers have officially opened up market for low cost ESP deployment which is a significant step change to conventional practice. This will be of great benefit to the upstream oil and gas industry, particularly for offshore assets with little infrastructure.
Kamat, Dahlila (PETRONAS Carigali Sdn Bhd) | Kadir, Zairi (PETRONAS Carigali Sdn Bhd) | Kumaran, Prashanth Nair (PETRONAS Carigali Sdn Bhd) | Ibrahim, Ramli (PETRONAS Carigali Sdn Bhd) | Ahmad, Mior Yusni (PETRONAS Carigali Sdn Bhd) | Madon, Bahrom (PETRONAS Carigali Sdn Bhd) | A Aziz, Adam Hareezi (PETRONAS Carigali Sdn Bhd) | Ishak, Mohd Faizatulizuddin (PETRONAS Carigali Sdn Bhd) | Gordon Goh, Kim Fah (Schlumberger) | Ceccarelli, Tomaso Umberto (Schlumberger) | Tan, Chee Seong (Schlumberger) | Kalidas, Sanggeetha (Schlumberger) | Mohd Salim, Ahmad Syahrir Hatta (Schlumberger) | Maldonado, Jorge (Schlumberger) | Lei Min, Zhang (Schlumberger) | P Mosar, Nur Faizah (Schlumberger) | Gil, Joel (Schlumberger) | Abdul Rahman, Mohd Ramziemran (Schlumberger) | Watana, Kulapat (Schlumberger) | Chabernaud, Thierry (Schlumberger)
The first horizontal oil well was drilled through an anticline structure in the Block-7E of East Flank, S-field, penetrating three production sands Sand I, Sand II and Sand III. Based on a comprehensive pre-drill study through steady-state and 3D dynamic time lapse simulation, Inflow Control Device (ICD) with integral sleeve (on/off function) attached to the ICD's joint is the optimum development of the fault block that maximizes zonal control for contrasting water encroachments. Due to the unconsolidated nature of the target reservoir, this well is designed for Open-Hole Gravel Pack (OHGP) with specialty 3D filtration screen to manage sanding issue. This paper highlights 2-in-1 application of ICD with enabled zonal shut-off sleeves and the OHGP completions with external screen. A pre-drilled ICD dynamic modeling is constructed to evaluate the well performance with ICD configuration. The design criteria for an optimum ICD design configuration is based on number of compartments and size, packer placement, ICD nozzle sizes and numbers. This dynamic single well model was used to justify the technology value which resulted in production improvement (maximizing oil and minimizing/delaying water). However, during the drilling of this well, the pre-drilled model is then updated in real time with the input of actual petrophysical data from Logging While Drilling (LWD) measurements along the OH section. Actual well trajectory and structure adjustment encountered while drilling were also co-utilized to determine the final optimum ICD design for the field run-in-hole (RIH) completion. Target fault block in S-Field East Flank requires optimum development strategy for its economic viability (
Sidek, Sulaiman (PETRONAS Carigali Sdn. Bhd.) | Hui Lian, Kellen Goh (PETRONAS Carigali Sdn. Bhd.) | Ching, Yap Bee (PETRONAS Carigali Sdn. Bhd.) | Trjangganung, Kukuh (PETRONAS Carigali Sdn. Bhd.) | Madon, Bahrom (PETRONAS Carigali Sdn. Bhd.) | Yusop, Zainuddin (PETRONAS Carigali Sdn. Bhd.) | Gundemoni, Bhargava Ram (3M Technical Ceramics) | Jackson, Richard (3M Technical Ceramics) | Barth, Peter (3M Technical Ceramics)
This paper will present the first successful application of ceramic sand screen in Malaysia. Oil production from the field has a long history beginning with the first production in 1972. A great number of sand control methods have been tested and applied in the field. Production history has showed instances of sand production contributed by factors such as in-situ stress changes, increase in water production and cascading effect from production operation activities. A few wells completed with primary sand control equipment have failed and remedial action by metallic through tubing sand screen experiencing rapid wear, forcing the operator to control sand production by beaning down the wells and closely monitoring sand production at surface overtime. Worse still, some of the wells had to be closed-in. Hence ceramic sand screen was considered as remedial sand control due to its superior durability and resistance compared to metallic sand screen.