In mature fields, improving oil recovery by waterflood in depleted sands while remaining below the desired gas/oil ratio (GOR) limits is always a challenge. A high GOR, inconsistent with reservoir modeling predictions, triggered a halt in production in one of the new updip producers in the field. Re-visiting the understanding of the reservoir fluid behavior and dynamic simulation model(s), and, most importantly, confirming the formation of a secondary gas cap triggered the planning and execution of a production logging program, a sampling program, and a series of well tests.
This paper presents a case study that shows how production, acoustic, and temperature dynamic modeling complemented each other to meet the logging program objectives: 1) confirm the source of gas (a gas cap versus differentially-depleted sand units); 2) obtain downhole samples with high cumulative oil content for geochemical and PVT (Pressure-Volume-Temperature) analyses; and, 3) design an optimized production/injection strategy that allows the operator to resume production under new conditions that control the GOR in the well.
Production logs were obtained using a third generation (Gen3) Production Logging Tool (PLT) run with an innovative combination of electrical, optical, and capacitance micro-sensors as well as doppler transducers flowing the well at two different production rates. A new advanced approach to processing optical data was used as part of an otherwise well-established analysis workflow. The log interpretation reveals a segregated well flow profile with negligible water production at depth, an intermediate oil zone with minimal gas holdup, and an upper gas-dominant zone. The High-Definition Spectral Acoustic (Noise) and High-Precision Temperature (SNL-HD and HPT, respectively) logs were obtained to model the allocation (producing versus non-producing sands) and quantification (oil versus gas volumes) of the reservoir flow, respectively.
While the well production profile suggests a potential secondary gas cap or a highly depleted gas-producing top sand layer(s), the high frequency acoustic measurements indicate radial reservoir flow from five main producing sand units, the deepest of which is a few feet above the bottom-most perforations. Temperature dynamic modeling indicates that each producing sand unit produces both oil and gas. The depths of the producing sand units, the produced hydrocarbon composition, and the well production profile indicate a depth mismatch between where the gas is produced in the reservoir and where it is seen in the well. A theory to explain this depth mismatch is annular gas flow in the lower completed well section, which would disprove the formation and existence of a gas cap.
Well tests and GOR calculations in the various producing sand units indicate an improved GOR and an increasing reservoir pressure (Pres), both of which were expected due to injection at high Voidage Replacement Ratio (VRR ≥ 1) and a pause in production in the well. Results from the analyzed downhole samples and extended well tests provided inputs to update reservoir models, PVT properties, and allow better predictions of Pres and GOR changes with production and injection. Additionally, PVT results, using the downhole fluid samples, helped engineer the original reservoir fluid composition (at virgin pressures) and narrow down the range of initial reservoir saturation pressure (Psat) in the updip location. Geochemical results also confirmed the connectivity of the oil column between updip and downdip locations. All observations, data, and modeling helped shape an optimized production strategy to be implemented in the well.
