Session 2
Wednesday, August 19th
8:00am – 9:00am US Central Time

8:00 AM

Experimental Study to Understand Formation Damage due to Asphaltene Deposition in a Deepwater Field

Gonzalez, D., Gramin, P., Haldipur, P. and Pietrobon, M., Upstream Technology and  BP America

Speaker Bio: Doris Gonzalez is a Reservoir Engineer / Fluid Specialist in the Global Modelling Team (GMT) at bp-America in Houston. She has more than 20 years of professional experience in the academia, polymers and oil industry. She was a Data Quality Manager and Project Engineer at the Schlumberger Reservoir Fluids Laboratory in Houston. Currently at bp, Doris provides technical support to different projects in the Gulf of Mexico, Middle East, Africa, South America and US unconventional. She is a co-author of several technical papers related to flow assurance, fluid characterization and general reservoir engineering topics. Doris is an officer of the AIChE-UEFA forum and member of the SPE. She holds a BSc in Chemical Engineering from the National University of Colombia, MSc from the University of Oklahoma and PhD from Rice University.

ABSTRACT: Asphaltene deposition near-wellbore results in impaired well performance leading to production losses and requires costly and periodic interventions to remediate the damage and maintain well production. Once the reservoir pressure falls below the asphaltene onset pressure (AOP), small asphaltene particles could generate porosity reduction due to deposition onto the rock surface. As pressure depletes further, asphaltene particles will aggregate and block pore throats which could lead to severe permeability reduction. In deepwater fields that are prone to skin growth due to asphaltene deposition, Operators need to define the operating envelope for their wells that reduces, if not eliminates, skin growth and prolongs the time duration between interventions.

The objectives of this work are to 1) to study the effect of asphaltene deposition on permeability reduction at reservoir conditions, and 2) to evaluate the effect of flow velocity on the rate of permeability degradation. This work presents the results obtained from core flooding laboratory tests carried out at reservoir conditions. The fluids used in this study were live pressurized MDT samples from different wells in the same reservoir collected during the drilling phase. The fluids from this reservoir have asphaltene onset pressures close to initial reservoir condition potentially promoting asphaltene precipitation and deposition in the reservoir rock. The core-flooding experiments were conducted with core plugs collected from the same reservoir. Different injection rates were used to test the effect of fluid velocity on the rate of deposition. This study differs from any previous work as equipment was upgraded from a maximum pressure handling of 10,000 psia (8,000 psi effective pore pressure limitation) to 20,000 psia as demanded by the deep-water environment. This allowed the laboratory tests to be performed at 13,500 psia and around 200oF.

The laboratory tests show evidence of permeability impairment occurring under dynamic flowing conditions. The laboratory results indicate that small particles that precipitated just below the AOP (with sizes smaller than the mean pore diameter) were continuously depositing on the rock surface and causing significant loss of initial oil permeability. The degree of permeability decrease was found to be a function of oil flowrate and oil throughput. However, asphaltene aggregates generated at lower pressures but above bubble point (with sizes above the mean pore diameter), blocked pore throats and generated severe permeability reduction by more than 80% of the initial permeability value. The skin growth observed in the field in wells from the same reservoir closely mimics these laboratory results.  This study provides additional insights into our understanding of the relationship between well-operating conditions and permeability impairment due to asphaltene deposition.

8:30 AM

Applications of Wireline Formation Testing: A Technology Update

Partouche, A., Edmundson, S., Tao, C., Chen, H., Nelson, K., Sawaf, T., Yang, B., Xu, L., Dindial, D., Pfeiffer, T.

Wireline formation testing has evolved from discrete pressure measurements, introduced in the 1950s to measuring pressure gradients and fluid contacts since the 1970s. Technology introduced in the late 1980s and onwards added interval pressure transient testing, focused sampling, and downhole fluid analysis. Thirty years later, this paper shows data examples of a recently developed formation testing platform in a wide range of environments, and applications, that change how we plan, acquire, and use formation testing.

The dual-flow-line architecture of the formation testing platform is designed to systematically address shortcomings of legacy technology, enabling focused sampling in the tightest conventional formations, as well as transient testing in high mobility environments.  Specialized pre-job planning software evaluates conveyance options to minimize friction and borehole contact, estimates the available flow rate, compares cleanup performance of the different inlets, and simulates transient testing responses. During the operation, the platform uses hardware embedded automation algorithms that execute routine tasks in a consistent and highly efficient manner, leaving more time for the user to focus on data quality and value of the measurements. 

Case studies from Mexico, Norway, and the US demonstrate specific improvements in capability and performance. Field data from Mexico shows focused sampling of gas condensate from a heterogeneous submillidarcy carbonate formation in an HP/HT well drilled with oil-based mud. Controlled downhole decompression of crude oil in the flowline at a sampling station in Norway enabled real-time measurement of its bubblepoint pressure to within 6 psi of that measured in the laboratory. Another case study integrates accurate relative asphaltene gradients into an existing reservoir fluid study to prove reservoir connectivity across a large lateral distance in a producing field. Application of the dual packer subsystem demonstrates inflation within four minutes and pure oil samples within 90 minutes on station in a 1.5-md/cp fractured basement formation. The fine pump control at a low rate enabled sampling just below reservoir pressure in Alaska and a case from the Gulf of Mexico demonstrates the real-time impact of fluid properties on the understanding of reservoir architecture and completion design.

The presented examples highlight the impact of downhole automation, define the new operating envelope for formation testing in the most challenging environments, and highlight how the technology development leads to decision making on a broad reservoir scale by providing contextual answers rather than an accumulation of facts and figures. 

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