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Burgan Marrat, a deep carbonate reservoir was transferred from exploration to development team for an accelerated production of the newly discovered oil. This multi-billion barrel reservoir is spread over 450 km2, has more than 40 faults, 8 compartments with large variation in oil-water contact and reservoir/fluid characteristics. The objective of this work is to understand the key uncertainties and quantify their impact on the reservoir offtake rate and oil recovery by conducting uncertainty assessment.
An interdisciplinary team identified the key uncertainty parameters expected to have significant impact on the reservoir development. The range and probability distribution law for each parameter was set considering the uncertainties due to limited measurements or variation in interpretations. A Response Surface Model (RSM) was created to evaluate the uncertainties by using a base dynamic model and applying an appropriate experimental design, which allowed to efficiently study the uncertainty space with a feasible number of simulations. Using the RSM, the primary effects and interaction between parameters were quantified to rank the uncertainties based on their impact on field production.
Key uncertainty parameters were identified including eight OWCs, six fault transmissibilities, horizontal and vertical permeability multipliers, and porosity multiplier. Latin Hypercube was found to be the appropriate Experimental Design for the study considering 17 parameters and the need of building a reliable RSM that includes interactions between them. The design recommended 155 simulation cases, which were prepared and submitted automatically by the software.
Multi-time Responses were analyzed qualitatively to identify the top 5 uncertainties having material impact on field production over 20 years considering 6 existing wells and 30 new well locations. The RSM quantitative evaluation showed three parameters (OWC2, OWC4 and OWC1) having a total effect on the response higher than 10%; followed by PERMX and OWC3 with less than 5%. The other 12 parameters have total effects less than 2%, and the interactions effect is less than 0.5% for any interaction between two parameters. Contrary to the intuition, none of the faults proved impact on the reservoir production.
The results prove very useful to make a right development and appraisal strategy in early life of the reservoir. The new well locations can be ranked and prioritized to optimize the development and effectively appraise the areas with high risks.
Uncertainty assessment has value throughout the life of the reservoir. However, this study indicates that its application in early life of the reservoir can bring immense value. An uncertainty analysis on the reservoir production helps in decision-making regarding the number of wells and their locations to reach a target production by managing the risks.
Altemeemi, Bashayer (KOC) | Gonzalez, Fabio (BP) | Al-Nasheet, Anwar (KOC) | Gonzalez, Doris (BP) | Al-Shammari, Asrar (KOC) | Sinha, Satyendra (KOC) | Muhammad, Yaser (Schlumberger) | Datta, Kalyan (KOC) | Al-Mahmeed, Fatma (KOC)
Sound development plans are based on complex 3-D 3-Phase multimillion grid reservoir simulation models. These models are used to run different scenarios where probability distributions are included to understand the impact of uncertainties and mitigate main risks that could raise during the life of the field. With today's available dominant supercomputers, reservoir engineers have the tendency to undervalue the power of classical reservoir engineering. However, in a fully connected reservoir tank that honors the basis of the material balance equation, material balance technique has been long recognized as a powerful tool for interpreting and predicting reservoir performance by estimating initial hydrocarbon in place and ultimate hydrocarbon recovery under various depletion scenarios. In brief, under the right conditions, material balance technique is a suitable tool for field development planning. The power of material balance to predict long term performance is undisputable, especially in the case of a prevailing uncertainty. This is the case of the Magwa-Marrat field, where the development plan has historically been driven by the potential risk of asphaltene deposition in the reservoir.
The objective of this paper is to show a step by step process to integrate data to build a reliable model using material balance and how this model is utilized to progress a field development plan capable of managing uncertainty and provide the tools to mitigate risk.
Pressure data is obtained from repeat formation tester (RFT), static data from shut-in pressures and reservoir superposition pressures from pressure transient analysis. The average reservoir fluids properties are retrieved from a compositional equation of state based on circa 20 PVT studies.
The material balance model was successfully completed, and the resulting stock tank oil initially in place (STOOP) was compared to volumetric calculations. Solution gas, rock compaction and aquifer influx were determined as drive mechanisms. The Campbell Plot, diagnostic tool, was proven to be prevailing defining early energy to determine STOOIP and the aquifer properties were calculated by matching the distal energy
The material balance model was then used to run different development strategies. This methodology captured the impact of depleting the reservoir down to Asphaltene Onset Pressure (AOP) as well as below AOP. The model was also used to define the requirements for water injection rates and startup of a water flooding project for pressure support. Additionally, the material balance work was implemented to support reservoir management and to maximize recovery factor.
This paper presents an innovative approach of integrating asphaltene behavior from laboratory tests and fluid studies, combined with material balance to screen development scenarios for an efficient depletion plan including water injection to manage asphaltene risks and optimize ultimate recovery. Finally, a fully ground-breaking strategy, not reported earlier to the knowledge of the authors, has been established to manage the perceived main risk in the Magwa-Marrat reservoir.
Al-Obaidli, Asmaa (KOC) | Al-Nasheet, Anwar (KOC) | Snasiri, Fatemah (KOC) | Al-Shammari, Obaid (KOC) | Al-Shammari, Asrar (KOC) | Sinha, Satyendra (KOC) | Amjad, Yaser Muhammad (Schlumberger) | Gonzalez, Doris (BP) | Gonzalez, Fabio (BP)
The Magwa-Marrat field started production early 1984 with an initial reservoir pressure of 9,600 psia Thirty-six (36) producer wells have been drilled until now. By 1999, when the field had accumulated ~92 MMSTB of produced oil and the reservoir pressure had declined to ~8000 psia, the field was shut-in until late 2003 due to concerns on asphaltene deposition in the reservoir that could cause irreversible damage and total recovery losses. The field was restarted in 2003 an it has been in production since then. By April 2018 the field had produced 220 MMSTBO, with the average reservoir pressure declined to 6,400 psia. As crude oil has been produced and the energy of the reservoir has depleted, the equilibrium of its fluid components has been disturbed and asphaltenes have precipitated out of the liquid phase and deposited in the production tubing. There is a concern that the reservoir will encounter asphaltene problems as the reservoir pressure drops further. The objective of this manuscript is to present the process to understand the reservoir fluids behavior as it relates to asphaltenes issues and develop a work frame to recognize and mitigate the risk of plugging the reservoir rock due to asphaltenes deposition with the end purpose of maximizing recovery while producing at the maximum field potential
Data acquired during more than 30 years have been integrated and analyzed including 22 AOP measurements using gravimetric and solid detection system techniques, 17 PVT lab reports, 1 core- flooding study and 1 permeability/wettability study.
Despite the wide range of AOP measured in different labs, it was possible to determine that the AOP for the Magwa-Marrat fluid is 5,600 ±500 psia and the saturation pressure is 3,200 ±200 psia.
Results of this fluids review study indicates that it might be possible to deplete the reservoir pressure below the AOP while producing at high rates. Additional field testing and lab research have been proposed to 1) establish an adequate operating envelop for each well to optimize production and mitigate asphaltene deposition in the tubing to decrease downtime due to coiled tubing cleanouts which will reduce OPEX, 2) Support determination of a suitable reservoir pressure depletion to minimize CAPEX by implementing a pressure support project at an optimum reservoir pressure, and 3) Establish an appropriate field development strategy to produce the field at its maximum potential without jeopardizing the health of the reservoir while optimizing ultimate recovery