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Gupta, Anish (PETRONAS) | Narayanan, Puveneshwari (PETRONAS) | Trjangganung, Kukuh (PETRONAS) | Mohd Jeffry, Suzanna Juyanty (PETRONAS) | Tan, Boon Choon (PETRONAS) | Awang, M Rais Saufuan (PETRONAS) | Badawy, Khaled (PETRONAS) | Yip, Pui Mun (PETRONAS)
A matrix stimulation candidate screening workflow was developed with the objective to reduce the time and effort in identifying under-performing wells. The workflow was initially tested manually for few fields followed by inclusion in Integrated Operation for an automated screening of wells with suspected formation damage. Analysis done in three fields for stimulation candidate selection will be displayed with actual statistics.
The main aim of the work was to digitalize the selection of non-performing candidates rather than manually looking into performance of each well. A concept of Formation Damage Indicator (FDI) was combined with Heterogeneity Index (HI) of the formations to screen out the candidates. Separate database sets of Reservoir engineering, Petrophysicist and Production was integrated with suitable programming algorithms to come up with first set of screened wells evaluating well production performances, FDI and HI trends up to over the last 30 years. The shortlisted candidates were further screened on the basis of practical approach such as gas lift optimization, production trending, OWC-GOC contacts, well integrity and well history to come up with second round of screened candidates. The final candidates were analyzed further using nodal analysis models for skin evaluation and expected gain to come up with type of formation damage and expected remedial solution.
For fields A and D with a total of 210 strings each, the initial FDI and HI screening resulted in 70 and 120 strings being shortlisted, respectively. This was followed by a second round of screening with 25 and 35 strings being further shortlisted as stimulation candidates, respectively. Nodal analysis models indicated presence of high skin in 90% of the selected wells indicating a very good efficiency and function-test of the workflow. In addition to selection of the candidates, the identification of formation damage type was compiled on an asset-wise basis rather than field basis which helped in more efficient planning of remedial treatments using a multiple well campaign approach to optimize huge amount of cost. The entire screening process was done in one month which was earlier a herculean task of almost one year and much more man-hours. With effective manual testing of the workflow in two major fields, workflow was included in Integrated Operations for future automation to conduct the same task in minutes rather than months.
With this digitalized unique workflow, the selection of under-performing wells due to formation damage is now a one click exercise and a dynamic data. This workflow can be easily operated by any engineer to increase their operational efficiency for flow assurance issues saving tons of cost and time.
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.
Mohd Hatta, Siti Aishah (PETRONAS Carigali Sdn Bhd) | Zawawi, Irzee (PETRONAS Carigali Sdn Bhd) | Gupta, Anish (PETRONAS Carigali Sdn Bhd) | Ahmad Nadzri, M. Safwan (PETRONAS Carigali Sdn Bhd) | Salleh, Nurfarah Izwana (PETRONAS Carigali Sdn Bhd) | Jeffry, Suzanna Juyanty M. (PETRONAS Carigali Sdn Bhd) | Sharif, Natasha Md (PETRONAS Carigali Sdn Bhd) | Ishak, Izza Hashimah (PETRONAS Carigali Sdn Bhd) | Maoinser, M. Azuwan (Universiti Teknologi PETRONAS)
Field B is a marginal green field located offshore Sarawak, Malaysia with formation depth of less than 1000 meters. The compressional sonic transit time range is from 100 – 115 μs/ft, which immediately triggered the possibility of using active downhole sand control as this range is assumed to be unconsolidated. However, the rock mechanical strength characterization tests from sidewall core indicated contradictory result of a consolidated formation. Since the field is considered as a small field, the cost of the well especially on downhole sand control device need to be extensively optimized. Hence, sand prediction study for a small green field development using field and laboratory measurements was performed.
Several methodologies of sand prediction were utilized to evaluate the optimum sandface completion and sand control management for the field. Empirical and analytical sand prediction based on the well logs, sidewall cores analysis, and sand prediction software are employed to evaluate the likelihood of sand production and the optimum well completion design for the field development. The available data from appraisal wells of Field B is also calibrated to the nearby brown field, Field A that has been producing for more than 30 years.
This paper will discuss on the sand onset prediction results between full perforation versus oriented perforation, and pressure depletion impact on the sand production. The study shows that the formation is not prone to sand production especially in the early part of the production life with high reservoir pressure and low watercut. The expected Critical Drawdown Pressure (CDP) generated from different methods show large variation of sand onset pressure if the sandface is completed using full perforation. Oriented perforation tremendously expands the sand free drawdown limit. Based on the results of the study, expected reservoir pressure depletion and watercut, the completion of the wells adopted Oriented Perforation with no other downhole sand control equipment.
This paper is beneficial for petroleum and well completion engineers especially on sand prediction part of well completion design in development stage. This will assist in ensuring the field meets the EUR and bring forward economic value as well as well integrity assurance.
Tugimin, M Azri Aizat (PETRONAS Carigali Sdn Bhd) | Kamat, Dahlila (PETRONAS Carigali Sdn Bhd) | Baghdadi, Faical (PETRONAS Carigali Sdn Bhd) | Gupta, Anish (PETRONAS Carigali Sdn Bhd) | Mohammad Azili, Ammar (Schlumberger) | Mohamed Hanafi, Muhammad Mukrim (Schlumberger) | Meza, David (Schlumberger)
Sand Monitoring workflow was introduced in R field to manage and minimize the risk that sand production poses to the production facility by monitoring the sand production and its resulting erosion rate, and raise alarm immediately when these conditions violates the allowable threshold. The workflow serves as an enabler to the sand management process that are put in place at the field. By leveraging the automation from IO and complement it with additional processes, we came up with a holistic approach that is used to minimize the risk to the production facility. The defined Sand Management methodology starts with the automated workflow processing. The workflow utilizes data from field sensors and processes them to conduct risk assessments, and some mathematical calculation that are based on proven correlations. Based on these processes, the workflow will generate output of sand production risk assessment, calculated erosion rate, estimated remaining pipe thickness as a result from the erosion rate and critical drawdown monitoring.
To complement the output from the workflow, additional processes that utilizes the outputs are introduced as part of the sand management process. Some of these additional processes are: Correlation calibration by comparing the estimated pipe thickness from the workflow against computerized radiography or unit thickness manual measurement. Conduct Sand Depositional modelling at the high-risk location identified from the workflow to optimize sand handling capacity and monitoring. Extend the monitoring by utilizing network modelling software to assess the erosional risk from interlink of pipelines between jackets. Choke health monitoring and estimation based on choke CV and modelling.
Correlation calibration by comparing the estimated pipe thickness from the workflow against computerized radiography or unit thickness manual measurement.
Conduct Sand Depositional modelling at the high-risk location identified from the workflow to optimize sand handling capacity and monitoring.
Extend the monitoring by utilizing network modelling software to assess the erosional risk from interlink of pipelines between jackets.
Choke health monitoring and estimation based on choke CV and modelling.
The sand monitoring workflow has increased personnel efficiency by automating repetitive and tedious work and give out the result in an easily interpreted manner. The automated alarm has been proven to be useful in proactively engaging operations to tackle the problematic matter. Production interruption related to sand production has been effectively reduced by 50% after the implementation of the new Sand Management methodology.
The introduction of the workflow into the new methodology uses marginal cost, but maximizes the return on existing asset through the realization of their production potential, as well as proving on how multidisciplinary integration and collaboration between operator and the service company can be successful in a mature field despite the risk associated.
Gupta, Anish (PETRONAS Carigali Sdn Bhd) | Kamat, Dahlila (PETRONAS Carigali Sdn Bhd) | Zulkapli, M Hanif B (PETRONAS Carigali Sdn Bhd) | Borhan, Nor Aisyah Bt (PETRONAS Carigali Sdn Bhd) | Kobbeltvedt, Asgeir (BRI) | Hammersmark, J. (BRI) | Jay, D. (Daya Maxflo) | Sam, A. (Daya Maxflo)
Sand Production is a challenge in the oil and gas (O&G) production and this was aggravated in last decade due to depleting reservoir pressure. Malaysian brown oil fields have been in production for the last 30-40 years and are reaching their maturity. This leads to low oil production with alarmingsand counts. As a rule of thumb, the production rate would be limited to flow beyond at sand count not more than 15 pptb. As a result, few thousand barrels are locked in within the field due to this limitation and lack of efficient sand separating mechanism at the surface.
The emphasis on sand management had always been on controlling the production of the sand by means of utilising various ways of active sand control methods available in the market. Typically, a producing field requires two (
Surface Sand Management is a newly developed process and engineered system made to handle maximum amount of sand at surface by both theoretical and practical studies for sand removal capability of the existing surface system which can increase production from the well. The concept is a combination of production optimisation and risk handling ability considering all the safety and thereby defining sand limit of a platform or a Pad rather than the complete field. This includes erosion limits (from erosion rate simulation), platform sand handling capacity (desander), procedures and guidelines for sampling, calibrated sand monitoring devices and transportation modelling.
Currently, static wellhead de-sander is a solution, but installed on a few wellheads with limited performance due to changes in flow regime and feed quality. Moreover, the excess pressure drop across the well head compromised well deliverability. For gas lifted wells, static well head de-sanders become obsolete when the flow conditions changed from initial design, such as different flow rates or start of slugging effect.
A pilot trial of a two-stage centrifugal motorised desander also known as
The pilot trial was conducted with total of three (
Gupta, Anish (Petronas Carigali) | Kamat, Dahlila (Petronas Carigali) | Hanif, M (Petronas Carigali) | Zulkapli, B (Petronas Carigali) | Borhan, Nor Aisyah (Petronas Carigali) | Kobbelvedt, Asgeir (BRI Cleanup AS) | Hammersmark, Jon Arne (BRI Cleanup AS) | Dorfman, Jay (DAYA Maxflo) | Yau, Sam Choon (DAYA Maxflo)
Sand production and sand handling at surface has been a continuous challenge for the Malaysian region wherein few oil fields are in production since 30–40 years. Few thousands of barrels are locked in within the field due to unavailability of an efficient sand separating mechanism at the surface.
The current static wellhead de-sanders are a solution, but only to certain extent. The limitation of these static types is exposed with the change in flow regime or well rates. Also, the excess pressure drop across the well head is a compromise of the well productivity. Static well head de-sanders tend to become obsolete equipment when the design conditions or environment are changed like flow rates or slugging effect, etc. especially for gas lifted wells. To overcome these challenges, a pilot trial of a two-stage centrifugal motorized de-sander also known as dynamic desander was proposed and a pilot was conducted in Malaysian offshore platform to prove the concept.
Rotary / motorized de-sander offered a unique concept of rate independent, high separation, bulk desander capability and insignificant pressure drop mitigating all the challenges of static ones. The sand separation was done in 2 stages – centrifugal and gravitational. The motor driven de-sander provided no pressure drop and the accumulator at the bottom of facilitated large quantity of sand separation. Online flushing of almost clean separated sand from the accumulator makes the technology much more favorable for offshore environment. The continuous weigh measurement of separated sand can be utilized as a very good sand management tool.
The pilot trial was conducted for less than a week with total of 3 wells flowing at flow rates ranging from 500 to 1500 blpd. A separation efficiency of 85% up to 99.9% was observed with a total of 3.6T of sand separated in four days of pilot duration. Due to safety concerns on simultaneous operations, the pilot was called off much earlier than the scheduled period.
Pilot trial also highlighted few limitations of desander technology like inefficient gas handling system, malfunctioned weight indicator especially during high gas inflow and overflow of large particles into the system especially with the inflow of high concentration of sand. Considering the uniqueness of technology, these limitations can be modified by the new design with certain manufacturing changes.
Overall the objective of the pilot was deemed successful which is to identify a better sand separation solution compared to conventional static de-sander for gas lifted environment, applicable to various well rate ranges as well as efficient sand disposal and quantification. The Company is looking to have another trial after required modifications in the existing design is fulfilled prior to include this in the inventory.
Characterization of in-situ stress is critical for fracture modeling and developing low permeability reservoirs. An optimum stimulation strategy is required to achieve and sustain the economically viable production from such reservoirs with hydraulic fracturing on the basis of robust formation stress information and modeling.
The Barmer Basin is situated in Western part India in the state of Rajasthan. Though the main prolific reservoir is Fatehgarh Formation, in northern part of the basin the shallower low permeability Barmer Hill (BH) Formation also contains significant hydrocarbon resources. The reservoir is a finely laminated siliceous unit of probable diatomitic origin with high porosity (25-35%) but low mobility (0.01-0.3 mD/cp). Hydraulic fracturing has been established the key to develop this reservoir.
An integrated formation evaluation was undertaken in Mangala Field to address the uncertainty in the in-situ stress properties of different units of the reservoir. Wireline formations tester's dual packer module was used to measure the in-situ stress in several zones of the Barmer Hill and shallower Dharvi Dunger formations using the micro-frac technique. The shallower Dharvi Dunger (DD) Formation was also a part of the stress testing to achieve the well integrity and confirming as a frac containment unit for Barmer Hill frac growth.
In-situ stress data was successfully acquired and profiling in the wells X and Y quantified and proved that a significant stress contrast exists among several layers of the BH and DD Formations. This critical information may lead to the revision of the planned hydraulic fracturing design wherein earlier assumption was less stress heterogeneity in different units. The results obtained were used to calibrate and update the frac model by developing an in-house stress correlation to quantify proper frac growth.
This procedure and application can be applied in successful exploitation strategy for other low permeability unconventional reservoirs.
Clastic gas reservoirs can be made economical through effective stimulation techniques. Hydraulic fracture mapping based on seismic techniques can lead to better understanding of the effectiveness of reservoir stimulation, when combined with in-depth reservoir geology and geophysical knowledge make development of such fields feasible.
Two stages, out of five hydraulic fractures stimulation were monitored and mapped in an attempt to assess the fracture propagation in a clastic gas reservoir located in Rajasthan, Western India. This was the first hydraulic fracture monitoring in India using downhole wireline sensors whereby recorded microseismic (MS) events indicating fracture growth as they are being created by rock failure. Events triggered by the stimulation treatment are detected and located in a four-dimensional (4D) space (space and time) relative to the well being treated.
The microseismic images indicate that fractures are well distributed within the Upper and Lower Fatehgarh formations, in the north-east south-west azimuth. The first monitoring was done on Stage-4 and recorded very few MS events, but indicated a relatively contained fracture. The fracture geometry estimated from the mapping matches closely with the parameters anticipated from the frac modeling work. The second monitoring was done on shallower Stage-5 and showed downward height growth during the initial stage of the treatment. This observation indicates that the hydraulic fractures may have intercepted a fault located within the treatment well. The result is being integrated with the planned stimulation model, mini-frac data, stress profile and other geological information. This will help in calibration of the stimulation model. Understanding of the fracture geometry from this technique along with the fracture geometry available from fracture modeling, well testing, etc. shall be combined to arrive at optimized designs for future fracturing campaigns in this clastic gas reservoir.
Arora, Gaurav (BJ Services Ltd.) | Stolyarov, Sergey Mikhalovich (BJ Services Company) | Gupta, Anish (Cairn Energy India Pty. Ltd.) | Purusharthy, Naresh Kumar (Cairn Energy India Pty. Ltd.) | Mathur, Mohit (Cairn Energy USA) | Singh, Ratan (Cairn India Ltd.)
The Raageshwari gas field is a relatively deep (3000m) unconventional volcanic reservoir with a gas column in excess of 800 m. Gas from the Raageshwari field is used to generate energy for production of waxy, high-pour-point crude in the nearby Mangala, Bhagyam and Aishwariya fields (which were discovered in January 2004) in Barmer basin, Western Rajasthan, India (Figures 1, 2). The gas reservoir has inherently low permeability, and hydro-fracturing treatment is essential for optimum production from the field. A series of hydro-fracturing operations have been carried out on the field and treatments optimized over a period of time. A recent fracturing campaign implemented a shift in perforation methodology from conventional e-line perforation to peroration using sand jetting through coiled tubing. This paper discusses the challenges that had been associated with hydro-fracturing work in the field and benefits achieved with sand-jet perforation technology.
Mishra, Satyabrata (Cairn Energy Pty Ltd) | Gupta, Anish (Cairn Energy India Pty. Ltd.) | Mathur, Mohit (Cairn Energy Pty Ltd) | Purusharthy, Naresh Kumar (Cairn Energy India Pty. Ltd.) | Wenk, Andrew D.G. (Cairn India Ltd.)
The Raageshwari Deep Gas (RDG) Field in the Barmer Basin, India is a lean gas condensate reservoir, with excellent gas quality of ~80% methane, low CO2 and no H2S. The productive zones are in volcanic rocks and volcanogenic sediments. From a permeability perspective, the RDG reservoir is similar to typical tight gas reservoirs in other parts of the world which cannot be commercially developed without large-scale hydraulic fracturing. Recent RDG hydraulic fracture treatments have been monitored with microseismic mapping technology. The microseismic data was acquired in June 2010 to quantify the trend of hydraulic fracture networks induced in a 5-stage stimulation program. The recorded P and S wave events were subsequently mapped in 3D space by fracture stage (in time) to effectively represent the onset, propagation and trends of the fractures and the extent, overlap or inter-connection of the resulting fracture networks. The initial objective of conducting microseismic mapping was only to calibrate the existing fracture simulator. Earlier hydraulic fracture treatments had been conducted with a conventional gas condensate frac design in mind, with targets of ~100m of frac length and a dimensionless fracture conductivity (FCD) ranging from 5-10. The initial frac schedules were designed with large pad and proppant stage volumes (~275,000lb of 20/40 ISP and 16/30 ISP). The efficacy of these fracture treatment designs was to be verified with the microseismic mapping technology. It was found that RDG does not have the typical tight gas reservoir architecture which was assumed for the initial frac designs, but consists of tight matrix porosity contained within a very complex network of natural fractures and planes of weakness with conjugate jointing. Hence the conventional fracture design was changed to deal with such fracture network for future fracturing campaigns.