This paper presents how the sand control and management strategies of an oil field were optimised after multiple well failures between 2014 and 2016. It describes the impact of the new strategies on oil production and net present value. Field E is a sandstone field with oil and gas-cap gas at initial conditions, and has been developed with 5 production wells, 2 water injection wells, and 2 gas injection wells. The first nine wells were drilled from an offshore platform and completed with sand screens between 2012 and 2013. Production commenced in late 2013, and by the end of 2016, multiple sanding events had been reported and four of the five production wells had died. The asset team was tasked with diagnosing the cause of the well failures and developing solutions. Pressure data suggested that three of the failed wells had tubing restrictions, and the fourth failed well had a blockage upstream of the BHP gauge. The sand count data suggested significant sand production prior to well failures, and sand was also recovered from the separators. Pressure transient analysis suggested that the field had a lower permeability than the pre-development estimate, and higher pressure drawdowns were needed to produce economic oil rates from the field. It was concluded that the well failures were most likely caused by the high pressure drawdowns, which pulled sand from the reservoirs, and led to screen breakage in at least two wells and screen plugging in one well. A decision was made to re-drill the failed wells in 2016, and complete them with frac-pack sand control solutions. The drilling and production performance of the first two new wells are presented in this paper. The asset team also implemented a new and improved sand management strategy in Field E. This paper presents the lessons learnt from a new oil field impacted by sand production. It also outlines practical well diagnosis and sand management strategies, and presents simple methods of preserving well integrity and cash flow in oil fields struggling to manage sand production in a 40 USD/barrel oil price environment.

This paper presents the lessons learned from optimising the sand control and management strategies of an oil field (Field E) after multiple sanding events and well failures. It presents how the old sand control solution was selected, the failure root causes, and the remediation options considered. The new sand control method, and the performance of two re-drilled wells after two years of production are also presented. Field E is a sandstone field with oil and gas-cap gas at initial conditions, and was initially developed with 5 production wells, 2 water injection wells, and 2 gas injection wells. The development wells were drilled from an offshore platform, and completed with stand-alone screens (SAS) in 2013. Oil production commenced in late 2013, and within three years, sand production was observed, and 4 of the 5 oil production wells had failed. The 4 wells were re-drilled in 2017, and the sand control strategy was changed from stand-alone screens to frac-packs. Key lessons learned include completing sand strength studies pre-development, avoiding off-the-shelf sand control solutions, and completing sand control design studies based on service contractor capability, fines control, oil production rates, and sand control as key selection factors. Nearby wells should be shut in during infill drilling operations to avoid short circuits, drilling mud losses, completions damage, and well integrity failures. It is recommended that the bean up procedures of wells with sanding events are changed to slow bean up to preserve well integrity, oil production, and cash revenues. The asset team should consider installing sliding sleeves or inflow control devices for zonal testing and to choke or close sand production zones if needed. The asset team should also consider installing a test pipeline and a test separator to allocate sand production volumes from each well, clean up new wells, sample the wells for water salinity measurements, and other benefits.

This paper presents how 4D seismic was used to boost the profitability of an infill production well (XA) in Field X located offshore Nigeria. Field X has an anticline dome structure with sizeable faults and turbidite sandstone reservoirs. It had under-saturated oil at initial conditions, and has been developed with 4 subsea production wells and 2 subsea water injection wells tied back to a leased FPSO vessel. An Eclipse simulation history match model was constructed in 2012 to support the infill production well proposals XA and XB. The simulation model estimated the oil recovery from infill well XA as 1.57 MMSTB, which was deemed uneconomic. A review of the 2012 simulation model used for the recovery assessment suggested that the XA area was swept by a nearby water injection well (W1). This did not agree with the 4D seismic data. The simulation model water cut in a nearby production well (P1) was also higher than the actual water cut. It was concluded that the simulation model did not represent actual reservoir performance. The simulation model was optimised by improving the XA infill well path penetration in the target reservoir formation. The connectivity between the W1 water injection well and the production wells was also evaluated. A seismic section between W1 and P1 showed a potential flow baffle between the wells. This baffle was added to the simulation model to delay the water between W1 and P1. Production data suggested that W1 was most likely connected to another production well (P3) via a high conductivity channel. The channel was added to the simulation model to divert most of the water from W1 to P3. These actions improved the P1 water cut and 4D seismic water saturation difference history matches, increased the XA infill well oil recovery by over 50%, and made the well economic. This paper presents a standard method of how 4D seismic data was used to support infill well planning, and can also be used to justify 4D seismic data acquisition. It is recommended that reservoir simulation models are history matched with 4D seismic and other geologic and production data prior to using the models for prediction and well placement. In this case study, 4D seismic data was used to improve the simulation history match and boost infill well economics. 4D seismic can also be used to locate sealing faults, evaluate fault seal breakdown, find infill well locations, and improve oil recovery.

This paper presents the lessons learnt during an intervention to remove a gas hydrate blockage and reinstate oil production from an oil well in Field D. It also uses economics to justify facilities projects for hydrate prevention and flow assurance. Field D is a deep water oil field with 10 subsea production and water injection wells tied back to a floating, production, storage, and offloading (FPSO) vessel. Field D was shut down for turnaround maintenance work during the summer of 2016. After the field was brought back online, one of the production wells (D2) failed to flow. An evaluation of the pressure and temperature data suggested that the well had a tubing restriction. This was attributed to hydrate formation and blockage caused by limited methanol injection capacity. A number of attempts were made to induce the well with no success. A subsea intervention vessel was then hired to execute a clean out intervention operation, and this restored oil production from the D2 well. To minimise hydrate blockage and oil production losses, the asset team completed a feasibility study to evaluate the viability of installing a second methanol umbilical and a test separator. The hydrate clean-out intervention reinstated oil production from the D2 well, and the feasibility study suggested that installing a second methanol umbilical and a test separator are economically attractive as standalone or joint projects. It is recommended that flow assurance strategies are regularly updated as production fluids change over the lives of petroleum fields, from dry oil production to high water cut production. This paper presents hydrate remediation steps in a producing oil field, and outlines practical methods to justify methanol umbilical capacity enhancement projects.

This paper evaluates the profitability of developing a Nigerian marginal oil field in a low oil price environment. The undeveloped asset is located offshore, and remains undeveloped due to field size and remote location. Recent seismic interpretation suggested that the field could be larger than previous estimates, and this triggered re-evaluation for development. Subsurface and economic assessments were completed to evaluate the profitability of developing the field, and the NPV, profit to investment ratio, DCFR, payback period, and breakeven oil price indicators are presented. The base case development scenario was unattractive, and additional sensitivities were completed to transform the marginal field into an attractive investment. The paper presents standard working practices used to evaluate the profitability of petroleum upstream assets. It also shows why economics is the bottom line of petroleum assets, recommends guidelines for selecting upstream investment projects and participating in petroleum licensing bid rounds, and illustrates how hydraulic fracturing has transformed low permeability oil fields in the USA into economic projects.