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.
George, C. O. (Department of Geological Sciences, Nnamdi Azikiwe University) | Thomas, S. W. (Chevron Nigeria Limited) | John, M. (Chevron Nigeria Limited) | Gani, A. (Chevron Nigeria Limited) | Emmanuel, A. K. (Department of Geological Sciences, Nnamdi Azikiwe University) | Norbert, A. E. (Department of Geological Sciences, Nnamdi Azikiwe University)
Post-drill pore pressure and fracture gradient analyses were carried out in an offshore hydrocarbon field, of Niger DeltaBasin, the G-field, using petrophysical logs, drilling parameters and pressure data. Four wells were analyzed and the results from the analysis will serve as a look back in building a Pre-Spud pore pressure and fracture gradient model for future drilling of exploration and production wells. The overburden gradient and normal compaction trend were generated based on an empirical formula. The pore pressure gradients were computed using the Eaton’s and Miller’s method respectively. Mud weights, drilling parameters and drilling events were used to calibrate the pore pressure gradients. Fracture gradient was computed using Mathews and Kelly’s method with pore pressure definitive, overburden gradient and effective stress ratio as the inputs. Based on the empirical methods, pressure transition zones were detected across the four wells with three (3) pressure ramps of magnitude of 1.23 ppg (Pound Per Gallon), 2.55ppg and 1.52ppg respectively. Pore pressure gradient model generated from the study revealed normally pressured zones at the shallower part of the unconfined section in all the wells within the range of 870 and 6273 feet TVD (True Vertical Depth) with an average shale pore pressure of 8.4ppg for Well 1,4715 and 9145 feet TVD with an average shale pore pressure of 8.5ppg for Well 2, 2614 and 7736 feet TVD with an average shale pore pressure of 8.39ppg for Well 3 and 4227 and 7972 feet TVD with an average shale pore pressure of 8.4ppg for Well 4. The top of the overpressured zones (>0.47 Psi/ft) (9ppg) were established across the four wells. The analysis of pore pressure of the field shows that the depth to the overpressured zones ranges from 7498 to 8859 feet TVD for Well 1,9825 and 13582 feet TVD for Well2, 7741 and 12264 TVD for Well 3 and 8307 and 12220 feet TVD for Well 4.
One of the many processes utilized by subsurface teams to grow / sustain production is infill drilling. The choice of whether an infill opportunity will be drilled is finalized with detailed economic evaluation after all subsurface assessments have been completed. The economics of a proposed infill opportunity is mainly impacted by cost and recovery. Recovery is a function of initial production (IP) rate and length of plateau (sustained) production at the IP.
This paper explores key considerations in the selection / determination of initial production (IP) rate for forecasting recovery from infill wells. Using history-matched simulation models, rate sensitivity analysis was carried out for each well per subsurface model realization (P10-50-90) of the reservoir of interest. IP rates were then selected to ensure that they gave optimum incremental recovery for each subsurface model realization without compromising the commercial viability of the opportunity.
The approach described in this paper not only provides a robust way of estimating IP rates, but also gives insights to (i) better understand the interaction between the IP rate and the recovery process and (ii) identify potential upside if the "best case" scenario is encountered when a well is drilled. This paper also poses questions around a need for an industry-standard methodology to signpost, measure and report IP rates after well start-up.
The objective of this paper is to share learnings from the Okan field, highlighting successful strategies adopted to mitigate reservoir and operational decline almost 8 years without producer drilling or major rig workovers. Value gained is quantified to show that over a third of the current Okan production is tied to strategies adopted during the period of interest.
Details of the different wellwork methodologies are provided to communicate how value was maximized using minimal cost. Key strategies adopted that have created the Okan success story over the period of interest include the jacket-centric rigless wellwork approach which has resulted in a drop in overall wellwork costs as multiple wells on the same jacket are worked over in one mobilization. The use of interwell gas lift systems for isolated jackets unlocked reserves that would otherwise be uneconomic because of costly pipelay. In addition to enhancing production from wells requiring gas lift, the conversion of idle oil line conversions to gas supply lines for gas lift ensured available facility assets are utilized, bringing pipelay savings as well as production gain. Also, taking full advantage of the Okan Gas Gathering and Compression Platform, production from reservoirs with high GOR has been optimized, resulting in oil and gas gain without routine gas flaring. Challenges encountered and lessons learned are also shared in this paper.
As a result of the strategies shared in this paper, the current Okan production is over 30% higher than what it would have been without the deployment of these strategies highlighted. The same strategies can be transferred to other assets to obtain optimum value in these times of low commodity prices.
Ogbuagu, Frank (Chevron Nigeria Limited) | Afolayan, Femi (Chevron Nigeria Limited) | Esan, Femi (Chevron Nigeria Limited) | Obot, Nsitie (Chevron Nigeria Limited) | Adeyemi, Ganiyu (Chevron Nigeria Limited) | Okpani, Olu (Chevron Nigeria Limited)
This paper summarizes the strategy adopted in the development of two thin oil rim reservoirs in Okan Field, Offshore Niger Delta, Nigeria.
Its objective is to elucidate the strategy, engineering analyses, subsurface assessment and production procedures set in place to optimally develop the reservoirs.
Both reservoirs have oil thickness of <30 ft with gas thickness of >100 ft. The adopted development strategy for the two reservoirs involves the drilling of 4 wells, 2 in each reservoir, to drain the remaining oil reserves, prior to gas development.
Because of structural and fluid contact uncertainties, soft landing was incorporated into the well designs. Shale-to-shale correlation was used for accurate horizon depth prediction and detailed simulation models with local grid refinements were employed to determine optimum well orientation, landing depth, lateral length and aquifer properties. Details on their use to maximize value are shared.
While drilling, Azithrak™, a Baker Hughes tool, was used in geosteering the lateral well section to determine distance of well to nearest conductive zone as part of the oil-water contact tracking. All available data - logs, cuttings, reservoir pressures and production data - was incorporated and used to validate fluid contacts data because of the impact of landing depth relative to the fluid contacts on oil recovery. Simulation results and operational constraints were used to set acceptable production limits to ensure delivery of target reserves.
All the four wells have been successfully drilled and completed, with the wells landed successfully within the thin oil column, at the optimized distance from the fluid contacts, with the wells producing at <0.55 percent water cut. Initial production performances of the four wells are in line with static and dynamic assessment forecasts.
Lessons learned and challenges encountered during this development are also captured in this paper.
Onyeji, J. A. (Chevron Nigeria Limited) | Adebayo, A. A. (Halliburton Energy Services) | Stafford, T. W. (Chevron Nigeria Limited) | Ekun, O. A. (Chevron Nigeria Limited) | Onu, H. (Halliburton Energy Services) | Nwozor, K. K. (Department of Geology and Petroleum Geology University of Aberdeen)
Geomechanical related drilling problems have always been the major cause of geologic non-productive time (GNPT) in drilling operations (complex and conventional wells) especially in deepwater basins, where billions of dollars are being spent while searching for solutions to drilling problems and developing remediation plans. Thus, real-time pore pressure monitoring is critical to ensuring safe and successful drilling operations. Typically, the only information available to the drilling engineer prior to well spudding are offset wells and predrill models (1D or 3D) built from offset wells data and other sources (regional, sub-regional, seismic etc.) and no two (2) wells are ever the same in terms of behavior, then the need for real time pore pressure (PP), Fracture Gradient (FG) and Wellbore Stability (WBS) monitoring in ground-truthing and calibrating the predrill model cannot be overemphasized. This paper describes how modern technology, innovative approaches, monitoring well behavior and effective communication helped in meeting the challenges of real time pore pressure and fracture gradient surveillance while drilling in environments with very narrow drilling mud weight windows, and where there is limited information on the formation pore pressure, subsurface rock properties, in-situ stresses and basins with little to no offset well information. Integration of multiple data sets [appropriate logging while drilling data (LWD), drill cuttings, drilling parameters, gas in mud, equivalent circulating density (ECD) and equivalent static density (ESD)] and well behavior/events to support and calibrate predrill petrophysical log-based pore pressure prediction models significantly aided in drilling two complex wells safely and successfully to the target reservoirs in cost effective manner in the study area. Mechanical cavings and reamer affected cuttings were easily differentiated from normal drill cuttings, and potential kick predicted even in the absence of pipe connection gas; where there is no sign of underbalanced drilling using predrill pore pressure/ fracture gradient/wellbore stability (PPFG/WBS) petrophysical logs-based model. The model formed the basis for the critical drilling operations decisions taken in these case studies; mud weight increase, setting intermediate casing shallower than planned, and well deepening. Factors such as abnormal high rate of penetration (ROP), drilling mud properties, high temperature, salinity and calcite cementation affect petrophysical data, thus relying only on the logging while drilling (LWD) data such as gamma ray, resistivity, and sonic logs for real-time pore pressure and fracture gradient analysis, especially when drilling deep wells is not recommended. The innovative approaches presented in this paper via its workflow compensate for potential limitations of LWD data.
Cement packer well work is a rig-less intervention method for accessing reserves above and between production packers. It is used to isolate a target completion interval from other hydrocarbon or non-hydrocarbon zones. Cement packer is used as an alternative to the conventional production packer. The key benefit of cement packer application is the cost savings (in the order of $MM) realized instead of using a major rig workover to achieve the same objective of isolation of a target interval. A key challenge however is the attendant increased skin caused by reduced perforation efficiency through the extra layer of cement plug. This paper addresses this issue by showing the work-around adopted by one of the Assets in Chevron Nigeria JV to improve well productivity.
Well-AA was evaluated and proposed for a zone switch non-rig workover intervention of the production interval from N-AA/Well-AA to K-AA/Well-5X reservoir in November 2012 using cement packer to isolate existing completion and recomplete in the new target reservoir. The zone switch and perforation were executed successfully via a cement packer operation but didn't flow after perforation. Several attempts to bring the well on production such as swabbing were made with no success. The outcome of the attempts indicated there was poor or lack of connectivity between the wellbore and the sand-face.
A well performance lookback was done to identify the well problem and it was recommended to re-perforate the proposed interval of the well and initiate gas lift. The recommendation for re-perforation was based on productivity index analysis of previous cement packer completions and the perforation gun performance with respect to the required penetration through the cement plug, tubing/casing and the formation. Estimated productivity index (PI) from two previous cement packer operations were the basis of the recommendation. Well-BD (was perforated twice) with calculated PI of 2 Bbls/Day/Psi and Well-CX (which was perforated once) with calculated PI of 0.3 Bbls/Day/Psi.
This paper will discuss the lessons learnt and best practice from re-perforation of Well-AA with a bigger and deeper penetrating perforation gun that restored initial production from 0 BOPD to 550 BOPD at natural flow condition via a SEWOP barge operation.
The need for reliable and efficient production forecasts for business planning cannot be overemphasized. Production Forecasts are the underlining basis on which many business decisions are made. They also serve as main input into economics and decision analysis and are used for project selection. Until recently many organizations tend to rely on deterministic forecasting methods with inherent pitfalls since they don't include uncertainties in the estimates. While there are existing methods such as reservoir simulation for generating probabilistic forecasts for oil and gas, those methods are either expensive or take too long to deliver or a combination of both. The substantial investment in time and capital make these tools less available for making day to day decisions and preparing annual business plans to identify targets for the upcoming year.
The Probabilistic Forecasting Tool (PFT) was developed as a cost effective and user-friendly tool for generating reliable probabilistic production forecasts for oil, gas and water. It enables oil and gas companies to estimate a range of production forecasts using several input parameters and to evaluate the impact of each of the input parameters on the forecasted production. This tool has also found wide application in preparing monthly production outlook which might be too granular and resource-inefficient for full-blown simulation modelling.
The PFT was developed in Microsoft Excel with a built-in decline engine and incorporates a wide variety of inputs such as peak production rate, decline rate, workovers, planned/unplanned downtime, new drills, rig schedule etc. on which sensitivity analysis could be conducted. Probabilistically combining the low, middle, and high estimates of the input parameters, the PFT uses monte-Carlo simulations and Excel macro automations to generate uncertainty ranges around the input parameters. The tool then generates a cumulative probability density function of the profiles from which the forecasts at different percentiles could be evaluated
This paper will describe the probabilistic Production Forecasting Tool (PFT), its application for short term oil, gas and water forecast using decline curve analysis engine (DCA) as its foundation. It will describe the workflow for the integration of different assumptions on projects, planned downtime and unplanned downtime and show a few case histories. The application of this tool has helped in reducing man-hours required to use complex reservoir engineering forecasting tool for the same purpose. This tool has shown reliability in the production forecast numbers compared to actual production data in over eight years of its application.
In early 2003, NNPC/Chevron Nigeria Limited Joint Venture swamp production had grown to over one hundred thousand barrels per day of oil and associated gas and water. However, all operations ceased in March 2003 as a result of civil unrest and security concerns. Production was fully suspended and all field personnel were evacuated. Subsequently, many Swamp facilities and flowlines were severely damaged, rendering all Swamp Assets inoperable. In 2004, a dedicated cross-functional team began work to restore full swamp operations resulting in ramping up of base production to over fifty percent of the shut-in production within 2 years primarily due to successful execution of three key reentry strategies. Reestablish a secure operating environment. Restore production through a phased reentry approach, building on successes and lessons learned. Applying ingenuity to accelerate production. This paper will discuss the focused ingenuity and associated best practices employed in 2004 and also the lessons learned that have accelerated a Nigerian Swamp Field production, while ensuring prudent reservoir management is maintained.
Ambastha, Anil K. (Chevron Nigeria Limited)
Nigeria has vast amount of gas and gas-condensate resources that have not been developed because of country’s traditional focus on oil reservoirs in the past. However, country is now embarking on a systematic development of gas resources. Objective of this study is to discuss issues being faced by all parties to evaluate gas resources and practical solutions to move forward with gas development on a large scale.
This paper discusses commercial (including team dynamics), technical, data analysis, and organizational capability issues relevant to development planning for gas fields. Practical solutions such as open and full communication among all stakeholders, due diligence to locate and analyze technical data, and proper bench-marking and testing of relevant recovery mechanisms in commercial software packages are proposed that would lead to proper evaluation of gas resources. It is emphasized that work alignment to resolve uncertainties and reach appropriate decisions is absolutely critical for project success. While practical solutions presented in this paper are especially geared toward gas field development, many of these thoughts and concepts are applicable for technical analysis of all petroleum engineering projects.