Maintaining a stable borehole and optimizing drilling are still considered to be vital practice for the success of any hydrocarbon field development and planning. The present study deliberates a case study on the estimation of pore pressure and fracture gradient for the recently decommissioned Volve oil field at the North Sea. High resolution geophysical logs drilled through the reservoir formation of the studied field have been used to estimate the overburden, pore pressure, and fracture pressure. The well-known Eaton’s method and Matthews-Kelly’s tools were used for the estimation of pore pressure and fracture gradient, respectively. Estimated outputs were calibrated and validated with the available direct downhole measurements (formation pressure measurements, LOT/FIT). Further, shear failure gradient has been calculated using Mohr-Coulomb rock failure criterion to understand the wellbore stability issues in the studied field. Largely, the pore pressure in the reservoir formation is hydrostatic in nature, except the lower Cretaceous to upper Jurassic shales, which were found to be associated with mild overpressure regimes. This study is an attempt to assess the in-situ stress system of the Volve field if CO2 is injected for geological storage in near future.
Seafloor 4D gravity is used to monitor changes in the distribution of density within producing reservoirs. The highest sensitivity is obtained when tracking contacts between fluids with high density contrast, like gas-water, gas-oil, or CO2-water in injection sites. The detection of fluid movements provides valuable information on aquifer strengths, lateral compartmentalization and permeability.
Seafloor subsidence is monitored in gravity surveys by means of an elaborate processing of seafloor pressure measurements. Subsidence is a required correction for the interpretation of gravity results, but it is in itself a valuable monitoring tool, sensitive to important reservoir and overburden properties. It directly relates to pressure depletion and lateral compartmentalization, and in some cases, it is a key factor for the safety of the installations.
When combined, simultaneous measurements of 4D gravity and subsidence provide valuable information from the areas of the field far away from monitoring and production wells.
A key step in the processing of both gravity and pressure data is correcting for ocean tides. Tides are monitored during the surveys by means of tide gauges, which are pressure sensors deployed at stable locations on the seafloor during the survey.
In this study, we first introduce the principles of the technology utilized in offshore gravity and subsidence monitoring surveys. Secondly, we review a few published field cases from fields on the Norwegian continental shelf. We then discuss the possibility of using an alternative sensor technology for tide gauges with a potential positive impact in data quality.
Presentation Date: Wednesday, October 19, 2016
Start Time: 2:45:00 PM
Presentation Type: ORAL
Field X in the North Sea was discovered in the 1980s, and large subsurface uncertainties exist regarding reservoir extent, fluid contacts, and reservoir properties. An integrated study was conducted to define subsurface models that honored the available data set and captured the uncertainty range. These subsurface models then were used in a dynamic realm to understand the effect of dynamic uncertainties such as aquifer strength, gas-cap size, and relative permeability, with an overall objective of generating low-, middle-, and high-case production forecasts. Available Data Two wells have been drilled in Field X, with Well X1 being the discovery well and Well X2 being the appraisal well (Figure 1 above). The two wells confirmed the presence of an oil rim, approximately 200 ft thick, overlain by a primary gas cap.
Field X in the North Sea was discovered in the 1980s, and large subsurface uncertainties exist regarding reservoir extent, fluid contacts, and reservoir properties. An integrated study was conducted to define subsurface models that honored the available data set and captured the uncertainty range. Available Data Two wells have been drilled in Field X, with Well X1 being the discovery well and Well X2 being the appraisal well (Figure 1 above). The hydrocarbon-bearing Tay formation was composed of thin-bedded sands, 3–5 ft thick. Data acquired from the wells included basic lithologs, reservoir pressures, fluid samples, and core data.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IPTC 18234, “Constraining Reservoir Models by Integrating Data Across Disciplines—A Case Study of a Thin-Bedded Turbidite Field in the North Sea,” by Manish K. Choudhary, SPE, Amit Keshri, SPE, and Kamalraj Mohan, SPE, Shell Technology Centre Bangalore, prepared for the 2014 International Petroleum Technology Conference, Kuala Lumpur, 10–12 December. The paper has not been peer reviewed.
Field X in the North Sea was discovered in the 1980s, and large subsurface uncertainties exist regarding reservoir extent, fluid contacts, and reservoir properties. An integrated study was conducted to define subsurface models that honored the available data set and captured the uncertainty range. These subsurface models then were used in a dynamic realm to understand the effect of dynamic uncertainties such as aquifer strength, gas-cap size, and relative permeability, with an overall objective of generating low-, middle-, and highcase production forecasts.
Two wells have been drilled in Field X, with Well X1 being the discovery well and Well X2 being the appraisal well (Fig. 1). The two wells confirmed the presence of an oil rim, approximately 200 ft thick, overlain by a primary gas cap. The hydrocarbon-bearing Tay formation was composed of thin-bedded sands, 3–5 ft thick. Data acquired from the wells included basic lithologs, reservoir pressures, fluid samples, and core data. Both wells had been production tested, which helped in understanding the producibility of these thin bedded zones. Seismic data in this area were processed and were also available for the feasibility study.
Regionally, the Eocene Tay formation is deposited in a structurally diverse basin, influenced by salt and gravity tectonics during the Late Jurassic and Early Cretaceous. The Tay formation can be subdivided into three major subunits— Upper Tay, Middle Tay, and Lower Tay.
A detailed interpretation of the seismic data was carried out during the study, which helped in mapping the top of the Tay formation, the top of the underlying Balder formation, and the top of the Chalk formation. A number of seismic attributes were extracted at the top of Upper Tay, but only the seismic amplitudes and spectral decomposition were useful in distinguishing the channel or fan sands from the background sediments. The seismic resolution was not good enough to distinguish Upper Tay from Middle Tay because of the low netto- gross ratio (NTG) of the formation and a change in the fluid fill. In the absence of a seismic mapped surface, no attributes could be extracted separately for the Middle Tay reservoir.
Depositional Model. The integration of seismic-amplitude maps along with well-log data gave some insights into the reservoir-sand geometries but did not establish a single depositional model conclusively. The amplitude map suggested that the deposits could be part of either deep marine feeder channels or turbidite fans. This uncertainty was because of the dimming of seismic amplitudes at the crest of the structure, suggesting the possibility of a lower NTG area. Multiple realizations of sand geometries were constructed with a mix of channels and lobe geometries. These models were different from one another but provided an exhaustive set of realizations.
Development study can be challenging when limited data is available, but cross-discipline interaction can greatly help to improve the understanding of the reservoir architecture.
A small undeveloped North Sea turbidite field, discovered in the 1980s, was recently revisited as part of a feasibility study. Two historical wells suggested the existence of thin sand beds three to five feet thick, however seismic attribute maps were inconclusive in distinguishing whether the sands were deposited as deep marine slope feeder channels or as turbidite fans. Geochemical and pressure data differences from the wells indicated a possibility of compartmentalization. The NtG estimated from the wells ranged between 10-30%, and as such large uncertainties exist in the reservoir properties and lateral extent.
Data available across all disciplines was integrated to define a range of possible Mutually Exclusive and Collectively Exhaustive field conceptual models. These were created by combining deep marine channels and turbidite lobe reservoir geometries. Sector models for both geometries were constructed and dynamically simulated to understand their impacts on recovery factor. The conclusions were used to calibrate the conceptual models and also to choose deterministic models representing low, mid and high case recoverable volumes.
An uncertainty of fluid-fill in the reservoir existed as the wells did not log fluid-contacts and had different RFT pressures. Multiple fluid-contact realizations were built that ranged from spill-point-based contacts to free water level. Realizations with perched water and stratigraphically trapped oil columns were constructed and then discarded, as the base reservoir required uplift which was greater than the seismic depth uncertainty. The realizations defined for sand distribution and fluid contacts were probabilistically combined to define the low, mid and high case realization models for the dynamic simulation. This integrated workflow helped define the worst and best case scenarios for the highly heterogeneous system with limited data.
The introduction of a small field allowance in the United Kingdom  has encouraged companies to revisit previously discovered fields for potential development. Many of these small fields were discovered in the 1980’s and 1990’s and have limited appraisal data, resulting in large sub-surface uncertainties. This makes the development planning quite challenging as smaller volumes in these fields often result in marginal economics. At the same time however, they offer a cheap development opportunity though a tie-in to a nearby facility. Such tie-ins also help in extending the life of the existing fields and facilities, thereby increasing overall value for the company.
Shell recently completed a development feasibility study for a small field, Field X located in North Sea, for possible tie-in with a nearby facility. The field was discovered in the 1980’s and large sub-surface uncertainties exist in reservoir extent, fluid contacts and reservoir properties. An integrated study was carried out to define sub-surface models that honored the available dataset and also captured the uncertainty range i.e. models being Mutually Exclusive and Collectively Exhaustive. These sub-surface models were then used in dynamic realm to understand the impact of dynamic uncertainties like aquifer strength, size of the gas cap and relative permeability with an overall objective of generating low, mid and high production forecasts.
Zakaria, Ahmed Salah El Deen (Advantek International Corp.) | Hafez, Mohamed (Informateks International) | Ochi, Jalel (Total) | Zaki, Karim S. (Advantek International Corp.) | Lololi, Mehdi (Advantek International Corp.) | Abou-Sayed, Ahmed S. (Advantek International Corp.)
Injection pressure fall-off (PFO) test analysis has proven to be a reliable vehicle for understanding and evaluating well performance. Recently the methodology has been extended to the understanding of injectors. This paper presents an optimization model for analysis and interpretation of PFO tests for fractured water injectors. An elliptical composite flow model mathematically represents the fractured injector well. The optimization scheme couples the mathematical model of the well with a Genetic Algorithm (GA) to reach the final solution. The pressure transients representing the behavior of an injector a closing fracture and the discontinuity in fluid mobility are best developed in elliptical coordinates. The methodology derives the dimension of the induced fractures, formation permeability, fracture conductivity and fracture face skin.
The current paper illustrates the solution methodology by showing the attained match for a West Africa offshore field case. The field case provides reasonable agreement for the fracture dimensions and characteristics as verified by other techniques.
Genetic Algorithms are one of the most common artificial intelligence techniques for optimization. The reported solution is obtained by applying a GA with a non-linear least square error function as an objective function. A special penalty function, mutation, crossover probabilities, and stopping criterion are used to obtain the global minimum of the objective function. The test data analysis is done through type curve matching of the pressure and its derivative by minimizing the objective function to help determine the parameters that provide the best match between the field data and the presented novel fractured injector type curves.
Sandface completions such as standalone screen completions have suffered from erosion problems for many years. A significant amount of catastrophic screen failures are considered to be the result of high velocities of solid's laden hydrocarbons creating hot spot areas in the interface between the sandface and the completion. Previous researchers investigated the change in permeability of failed rock into annular gaps generated in non-compliant sand control completions and identified that packed material in this space can result in severe distortion to flow patterns and restrictions. This paper describes the development and testing process for a new methodology that allows identification of the erosion prone areas in the annular space between the sandface and the screen. Detailed investigation, supported by laboratory testing, reviewed oil and gas well conditions at the startup, during a cleanout and after hydrocarbon's production have been stabilised. Radial flow, mode of sand collapse, compaction, voidage, sand quality and formation petro-physical properties were tested and analysed using high and low pressure flow cells in order to quantify the changes in pressure drops through the collapsed rock material. The results indicated that flow rate, viscosity, voidage, grain shape and volume are the main contributors to the variations in pressure drops across failed sand material in the annular space. On the basis of these tests, a continuous (foot-by-foot) analytical model was developed that allows identification of the specific location and variation in pressure drops across the annular packed material for oil and gas wells. The model is composed of five (5) main elements; a reservoir inflow module, a fluid drag module, a grain size and volume module, a pressure drop module and an erosion prediction module. The model was tested using data from a North Sea field and the results, algorithms and field samples will be discussed and presented in detail.