Usop, Mohammad Zulfiqar (PETRONAS Carigali Sdn. Bhd.) | Suggust, Alister Albert (PETRONAS Carigali Sdn. Bhd.) | Mohammad Razali, Abdullah (PETRONAS Carigali Sdn. Bhd.) | Zamzuri, Dzulfahmi (PETRONAS Carigali Sdn. Bhd.) | M. Khalil, M. Idraki (PETRONAS Carigali Sdn. Bhd.) | Hatta, M. Zulqarnain (PETRONAS Carigali Sdn. Bhd.) | Khalid, Aizuddin (PETRONAS Carigali Sdn. Bhd.) | Hasan Azhari, Muhammad (PETRONAS Carigali Sdn. Bhd.) | Jamel, Delwistiel (PETRONAS Carigali Sdn. Bhd.) | Ting Yeong Ye, Diana (PETRONAS Carigali Sdn. Bhd.) | Abdulhadi, Muhammad (Dialog Berhad) | Awang Pon, M Zaim (Dialog Berhad)
Reservoir G-4, a depleted reservoir in field B had been producing from 1992 to 2015 with a recovery factor of 30% before the production was stopped due to low reservoir pressure. Due to the huge inplace volume. A secondary recovery screening was conducted and gas injection was identified as the most suitable solution to revive G-4 reservoir due to its low cost impact of 0.4 Mil. USD whilst managing to deliver the same results as other solutions (i.e. Water injection & Water Dumpflood).
The project had utilized existing facilities in field B including a gas compressor. The project required only minor surface modification to re-route gas into the tubing of injection well BG-03. From simulation results, a continuous injection of 5 MMscf/d will increase the reservoir pressure by 150 psia in 9 months, with incremental potential reserves of atleast 5.0 MMstb from the benefitter wells, BG-02 & as well as incoming infill wells BG-14 & BG-15. It is also envisaged that with future development of additional infill wells, the recovery factor will be increased up to 60%.
In term of gas management, field B is able to deliver additional 15 MMscf/d post petroleum operation reduction (i.e. Fuel Gas, Instrument Gas & Gas lift). With the initiation of gas injection, the project had managed to utilize and optimize 33% of additional gas production for reservoir rejuvenation purposes.
The paper provides valuable insight into the case study and lesson learned of maximizing oil recovery through gas injection with minimal cost incurred. The approach is highly recommended to maximize oil recovery especially in mature fields with similar reservoir conditions and production facilities.
Offshore oil and gas field developments are capital-intensive projects that require extensive facilities to drill, produce and transport the hydrocarbon from the reservoir to the processing plant. Determining the site, number and size of these facilities are amongst the most important decisions impacting a project's success. Here, we present a novel strategy to assist in these decisions by combining a stochastic optimization routine with a Virtual Reality (VR) Aided Design. The model uses a discrete-network optimization algorithm that employs a Monte Carlo Markov chain to explore feasible configurations that minimize the development's investment. It integrates the optimization with a state-of-the-art VR environment to allow the engineer to both monitor the progress of the optimization and help guide the field development in real time.
We present results illustrating how the approach can be employed in field developments to connect well targets to processing facilities. The model determines the optimum location, size and number of offshore well-head platforms, tie-in facilities, well paths and pipeline routes. It incorporates critical technical considerations for the design of drilling paths (e.g. dog leg severity) and surface facilities (e.g. water depth). The model has been applied to real data from offshore field developments in the North Sea and the Gulf of Mexico. Results including the investment value and optimum configuration are shown and supplemented with graphics from the VR environment. The VR technology enables a novel approach to optimize the development. The immersive platform lets the user not only visualize the field, it is also capable of providing real-time interaction with the computer-generated design. This allows the integration of engineering intuition and experience to enhance the development and eliminate infeasible or unfavorable configurations.
Hassan, M. Hafiidz (PETRONAS Carigali Sdn. Bhd.) | Rusman, Liyana (PETRONAS Carigali Sdn. Bhd.) | Chandrakant, Ashvin A. (PETRONAS Carigali Sdn. Bhd.) | Haslan, M. Hanif (PETRONAS Carigali Sdn. Bhd.) | Moktar, Nur Syazwani (PETRONAS Carigali Sdn. Bhd.) | Abdussalam, Khomeini (PETRONAS Carigali Sdn. Bhd.)
Matrix acidizing is an attractive treatment choice in clastic reservoirs to remove near-wellbore damage due to its relatively low cost. It has been executed countless times in brownfields East Malaysia with a moderate to high success rate to arrest production decline due to fines migration and scale deposition. Nonetheless, there is a critical need to look back on the choice of treatment chemicals and treatment approach in order to ensure optimum chemical volume, attractive production gain and higher success rate, especially in the current low oil price era. This paper will focus on the planning and successful execution of single-stage acid (SSA) combined with wax solvent stimulation treatments resulting in fourfold increase in net oil production post treatment in two wells in Field X offshore East Malaysia.
Well A18 and C33 experienced production impairment due to formation damage fines and organic scale. Combination of both wax solvent and SSA in the same treatment was used to remove the damage. Application of SSA eliminates the need for hydrochloric acid (HCl) pre and post flush thus reduces treatment volume, simplifies treatment execution and consequently reduces overall treatment time. Additionally, the usage of retarders eliminates fast reaction of hydrofluoric acid (HF) thereby allowing for deeper HF penetration. This paper also discusses the rapid decline observed post treatment for Well A18 is mainly contributed by re-mobilization of fines due to higher flow rates and re-buildup of wax within tubing and near wellbore. Proactive measures such as pressure drawdown management are suggested to prevent reoccurrence in future stimulation treatments.
In conclusion, this paper finds that the combination of wax solvent and SSA was successful in both removing the damage and optimizing treatment schedule. Correct identification of damage source coupled with good treatment design was able to quadruple production from well A18 and C33 in Field X.
This paper presents an innovative approach and cost effective solution in successfully mitigating formation damage caused by a combination of fines migration and organic scale. This single-stage stimulation treatment saves time, treatment volume and reduces job complexity.
Olatunji, Idris (Shell Nigeria Exploration and Production Company) | Ogunsina, Oluseye (Shell Nigeria Exploration and Production Company) | Okosun, Joshua (Shell Nigeria Exploration and Production Company) | Horsfall, Ipalibo (Shell Nigeria Exploration and Production Company) | Agbahara, Chidi (Shell Nigeria Exploration and Production Company) | Smith, Seun (Shell Nigeria Exploration and Production Company) | Yahaya, Ismael (Seplat) | Ogoja, Oluwafemi (Schlumberger)
This well was drilled and completed as a Frac & Pack oil producer with subsea wellhead in 3300 ft water depth. Despite all the care taken to maintain cleanliness during completion, initial performance on starting up the well indicated that it was severely impaired during the drilling phase with drawdown as much as 2300 psi observed. The well initially failed to reach the Hydrate Dissociation Temperature (HDT) of 35C within the specified period of 1 hour.
The well was eventually successfully started and some performance improvement was observed as the well was cleaned up gradually over the next few months but the potential of the well had to be revised down from the planned 30kbpd to 12kbpd to honour drawdown limit of 350psi.
This paper documents the effort made to restore the well’s planned production of 30kbpd by acid stimulation treatment by bullheading from the rig. From the well history, the source of impairment was attributed to drilling fluids. Thus, a half-strength mud acid was chosen as the treatment fluid and the placement was by high-rate bullheading from the rig connected to the subsea Xmas tree via a riser and EDP/LRP. The risk of flowing unspent acid through subsea flowlines and topsides equipment on the FPSO was assessed. Corrosion simulation studies showed the subsea flowlines can withstand the possible unspent acid with proper dilution by flowing high water cut wells at high rate through the same bulk flowlines being used to unload the just treated well. The dilution also helped protect the topsides equipment while further protection was provided by injecting diluted sodium hydroxide into the flow stream as it enters the topsides.
The result of the treatment was that productivity index increased by a factor of 3 from 27 bpd/psi to ca. 90 bpd/psi and the well is now producing at 30 kbopd.
Teklu, Tadesse Weldu (Colorado School of Mines) | Brown, Jeffrey S. (Colorado School of Mines) | Kazemi, Hossein (Colorado School of Mines) | Graves, Ramona M. (Colorado School of Mines) | AlSumaiti, Ali M. (The Petroleum Institute)
In petroleum reservoirs only a small fraction of the original oil-in-place is economically recovered by primary, secondary, and tertiary recovery mechanisms. A considerable amount of hydrocarbon ends up unrecovered or trapped due to microscopic phase trapping in porous media which results in an oil recovery factor typically less than 50%. Waterflooding is by far the most widely used method to increase oil recovery. The oil that remains in the porous media after waterflooding is called remaining oil saturation (ROS) which is larger than the relative permeability residual oil saturation (Sorw or simply Sor). This residual oil saturation varies depending on lithology, pore size distribution, permeability, wettability, fluid characteristics, recovery method, and production scheme. The Sor represents a statistical average over a wide range of pore scale residual saturations with in a representative elementary volume (REV). Determination of the residual oil saturation of a reservoir is a key parameter for reserve assessment and recovery estimates. Further, reliable Sor data is important for investigation of potential incremental recovery under Enhanced Oil Recovery (EOR) methods.
Various residual oil saturation measurement techniques are available both at laboratory and field scale. None of the techniques can be regarded as a single best method of determining Sor. Depending on the complexity of the reservoir under study, combinations of methods are always advisable for appropriate Sor determination. This paper catalogues a number of field case studies which use different techniques of determining Sor and ROS in sandstone and carbonate reservoirs.
Only part of the original oil-in-place is economically recovered by conventional methods. Due to macroscopic and microscopic phenomena, a considerable amount of hydrocarbon is unrecovered or trapped during multiphase flow in porous media. Determination of residual oil saturation (Sor) is a fundamental requirement for studying and understanding the behavior of a field during waterflooding and beyond. Especially, before embarking on a tertiary recovery scheme, it is imperative to know the Sor of the reservoir in order to assess its technical feasibility and profitability.
2. Residual Oil Saturation Determination Techniques
There are several ways to determine or estimate the residual oil saturation (Sor ) or the remaining oil saturation (ROS). These include core analysis methods, well log methods, and other methods. Teklu et al., 2013 gives a more detailed review of the techniques and when they are applicable. Table 1 lists the advantages and disadvantages of some of these techniques applied in the case studies.
Radford, S. (Baker Hughes Inc) | Desselle, S. (Baker Hughes, Inc.) | Enterline, J. (Baker Hughes, Inc.) | Allain, M. (Baker Hughes, Inc.) | Oliveire, J. (Baker Hughes, Inc.) | Pearl, B. (Chevron North America Exploration and Production Co.) | Palmer, J. (Chevron North America Exploration and Production Co.)
In today's oil and gas industry, reducing drilling time and cost has become more and more important as wells have been drilled deeper and costs have risen. This paper will describe a case study of a well drilled in the Main Pass area of the Gulf of Mexico for a major operator. In this job, in order to eliminate a trip and significantly reduced costs, it was required to rotate a bottomhole assembly (BHA), including an expandable reamer, across a whipstock.
This well contained several unusual challenges that will be described, including a shallow kick off and a subsequent extended-hole section to reach a proposed total depth (TD) in excess of 10,000 ft, drilling through sand and shale.
The paper will describe the team process, coordination and communication required between the operator and service companies to make this unique job successful. Offsets will be compared with respect to drilling dysfunction, vibrations, time, costs, and the like.
To reduce cost and non-productive time (NPT), it was decided to forgo drilling a long rathole out of the whipstock and proceed immediately with reaming on the next trip in. This approach required rotating the closed reamer across the whipstock, necessitating a series of analyses to limit the risk while performing this unusual feat. Extra trips were eliminated by using innovative well planning, procuring downhole tools with reputation of toughness and reliability, and finally requiring excellent cooperation between all involved parties. This job was confirmed to have saved the operator 29 hours of rig time and in excess of $250,000, while reducing the drilling plan by two days.
Deri, Charles (Schlumberger) | Hebert, John (Schlumberger) | Peternell Carballo, Ana Gabriela (Stone Energy Corporation) | Fisher, James (Stone Energy Corporation) | Gibbs, Rudolph (Cornell Petrophysics) | Cornell, Robert (Schlumberger) | Moreno, Javier
Logging while drilling (LWD) technology has been used successfully to overcome the drilling challenges when exploring a caprock hostile environment in the Main Pass area of the Louisiana Gulf Coast. Because of the geological setting, special steps needed to be taken to mitigate the obstacles and uncertainties while drilling. Successful acquisition and application of selected measurements led to achieving the drilling and formation evaluation objectives.
To drill the optimal wellbore, seismic-while-drilling technology was employed to optimize casing depths and minimize drilling risks such as mud losses and potential H2S. Additional techniques were used to help make the decision to set casing and maintain a viable wellbore for logging and completing the well.
For the second challenge, providing formation evaluation without compromising drilling safety and data quality, additional LWD services were applied. A resistivity-at-the-bit laterolog imager and a multifunction formation evaluation platform were employed to satisfy both the drilling demands and the formation evaluation needs. Having drilling mechanics and formation evaluation measurements available provided not only advanced measurements closer to the bit, giving a better chance of reducing invasion effects, but also impacted the drilling time through shorter rathole section. In addition, the laterolog resistivity imaging provided dips and texture information to map the structure and identify different geological features. Using these technologies, 100 ft were drilled into the caprock with enough information to evaluate the economical value of the prospect reservoir. The combination of these technologies and the ability to interpret the data streamed while drilling allowed the operator to successfully set casing at the top of the limestone caprock. In the end, the drilling risks and uncertainties experienced in the past were totally eliminated by the proper use of LWD technology.
This paper details the laboratory evaluation and product development for auniquely applied gas-lift paraffin inhibitor. Several crude oils, specific toone particular Gulf of Mexico subsea network, were characterized with respectto cloud point, pour point and paraffin content. This information was used todetermine suitable wax inhibitors to test for application into the productionfluids offshore. Cold finger wax deposition tests were performed to evaluateeight different inhibitor chemistries.
Details are given on the test methodologies used, with particular focus on thespecific evaluation to determine gas-lift suitability. Volatile flash analysiswas performed by a third party laboratory, coupled with a unique dynamicgas-lift test method, to find a suitable candidate. Of the products tested, twonew and specific formulations were developed for gas-lift applications thatdisplayed low weight loss and very little increase in viscosity.
There is very little documented in open literature on the formulations and testmethodologies employed to evaluate paraffin inhibitors for gas-liftapplication. This paper describes the most important treatment parameters anddetails on how gas-lift application was performed. This includes somesignificant learning lessons on the design and implementation of gas-liftparaffin inhibitors, as well as conclusions regarding the most appropriatedeployment parameters to avoid gunking and clogging of injection systems. Italso details the specific chemistries that can and should be used for this typeof application.
This paper concentrates on the challenges, experience and lessons learned during the Precommissioning and Commissioning (PCC) of the Blind Faith 14?? to 18?? gas export pipeline.
The PCC for the Blind Faith gas pipeline took place in 2008 and was an extremely challenging phase of the project. The challenges were associated with the complexity of the subsea architecture at the interconnection of the new Blind Faith gas pipeline and the existing Canyon Chief gas pipeline (Refer to OTC paper 19764 for the tie-in between Blind Faith and Canyon Chief systems). The complexity was further challenged by the need to minimize the amount of shut in days for the production of the Canyon Chief gas pipeline. The PCC occurred in two phases:
Phase I - Without shutting in existing production on Canyon Chief gas pipeline:
Phase II - Shutting in existing production on Canyon Chief gas pipeline:
The PCC architecture and commissioning challenges included the following:
The PCC effort took approximately three months to complete, during which time the project experienced two back to back hurricanes and Phase I was performed twice due to pig related issues.
The paper reviews and evaluates the demand - supply scenario and likely trends of the emerging gas markets in India.
With recently discovered gas reserves, the country's domestic supply is expected to increase at least double by 2011-12. The demand too is expected to increase
significantly by 2011-12 in keeping with the GDP growth rate of the country. This paper focuses on three main issues;
• The potential and limitations of domestic gas production/supply scenario in India.
• Opportunities arising out of policy initiatives being taken by the Government of India though skewed development of the market due to regulated gas pricing may be a deterrent.
• The options available to meet the increasing demand for natural gas covering LNG imports, CBM, gas hydrates and under ground coal gasification (UCG) and opportunities for importation of natural gas through pipeline vis-à-vis the existing geopolitical scenario will also be probed into.
The paper demonstrates the upcoming opportunities in the promising Indian gas business and challenges thereof.