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Collaborating Authors
Gonzalez, Fabio
Material Balance Based Development Plan for an Asphaltenic Reservoir Fluid Field
Altemeemi, Bashayer (KOC) | Gonzalez, Fabio (BP) | Al-Nasheet, Anwar (KOC) | Gonzalez, Doris (BP) | Al-Shammari, Asrar (KOC) | Sinha, Satyendra (KOC) | Muhammad, Yaser (Schlumberger) | Datta, Kalyan (KOC) | Al-Mahmeed, Fatma (KOC)
Abstract Sound development plans are based on complex 3-D 3-Phase multimillion grid reservoir simulation models. These models are used to run different scenarios where probability distributions are included to understand the impact of uncertainties and mitigate main risks that could raise during the life of the field. With today's available dominant supercomputers, reservoir engineers have the tendency to undervalue the power of classical reservoir engineering. However, in a fully connected reservoir tank that honors the basis of the material balance equation, material balance technique has been long recognized as a powerful tool for interpreting and predicting reservoir performance by estimating initial hydrocarbon in place and ultimate hydrocarbon recovery under various depletion scenarios. In brief, under the right conditions, material balance technique is a suitable tool for field development planning. The power of material balance to predict long term performance is undisputable, especially in the case of a prevailing uncertainty. This is the case of the Magwa-Marrat field, where the development plan has historically been driven by the potential risk of asphaltene deposition in the reservoir. The objective of this paper is to show a step by step process to integrate data to build a reliable model using material balance and how this model is utilized to progress a field development plan capable of managing uncertainty and provide the tools to mitigate risk. Pressure data is obtained from repeat formation tester (RFT), static data from shut-in pressures and reservoir superposition pressures from pressure transient analysis. The average reservoir fluids properties are retrieved from a compositional equation of state based on circa 20 PVT studies. The material balance model was successfully completed, and the resulting stock tank oil initially in place (STOOP) was compared to volumetric calculations. Solution gas, rock compaction and aquifer influx were determined as drive mechanisms. The Campbell Plot, diagnostic tool, was proven to be prevailing defining early energy to determine STOOIP and the aquifer properties were calculated by matching the distal energy The material balance model was then used to run different development strategies. This methodology captured the impact of depleting the reservoir down to Asphaltene Onset Pressure (AOP) as well as below AOP. The model was also used to define the requirements for water injection rates and startup of a water flooding project for pressure support. Additionally, the material balance work was implemented to support reservoir management and to maximize recovery factor. This paper presents an innovative approach of integrating asphaltene behavior from laboratory tests and fluid studies, combined with material balance to screen development scenarios for an efficient depletion plan including water injection to manage asphaltene risks and optimize ultimate recovery. Finally, a fully ground-breaking strategy, not reported earlier to the knowledge of the authors, has been established to manage the perceived main risk in the Magwa-Marrat reservoir.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.81)
Understanding Reservoir Fluid Behavior to Mitigate Risk Associated to Asphaltene Deposition in the Reservoir Rock Near to Asphaltene Onset Pressure AOP in the Magwa Marrat Depleted Reservoir
Al-Obaidli, Asmaa (KOC) | Al-Nasheet, Anwar (KOC) | Snasiri, Fatemah (KOC) | Al-Shammari, Obaid (KOC) | Al-Shammari, Asrar (KOC) | Sinha, Satyendra (KOC) | Amjad, Yaser Muhammad (Schlumberger) | Gonzalez, Doris (BP) | Gonzalez, Fabio (BP)
Abstract The Magwa-Marrat field started production early 1984 with an initial reservoir pressure of 9,600 psia Thirty-six (36) producer wells have been drilled until now. By 1999, when the field had accumulated ~92 MMSTB of produced oil and the reservoir pressure had declined to ~8000 psia, the field was shut-in until late 2003 due to concerns on asphaltene deposition in the reservoir that could cause irreversible damage and total recovery losses. The field was restarted in 2003 an it has been in production since then. By April 2018 the field had produced 220 MMSTBO, with the average reservoir pressure declined to 6,400 psia. As crude oil has been produced and the energy of the reservoir has depleted, the equilibrium of its fluid components has been disturbed and asphaltenes have precipitated out of the liquid phase and deposited in the production tubing. There is a concern that the reservoir will encounter asphaltene problems as the reservoir pressure drops further. The objective of this manuscript is to present the process to understand the reservoir fluids behavior as it relates to asphaltenes issues and develop a work frame to recognize and mitigate the risk of plugging the reservoir rock due to asphaltenes deposition with the end purpose of maximizing recovery while producing at the maximum field potential Data acquired during more than 30 years have been integrated and analyzed including 22 AOP measurements using gravimetric and solid detection system techniques, 17 PVT lab reports, 1 core- flooding study and 1 permeability/wettability study. Despite the wide range of AOP measured in different labs, it was possible to determine that the AOP for the Magwa-Marrat fluid is 5,600 ±500 psia and the saturation pressure is 3,200 ±200 psia. Results of this fluids review study indicates that it might be possible to deplete the reservoir pressure below the AOP while producing at high rates. Additional field testing and lab research have been proposed to 1) establish an adequate operating envelop for each well to optimize production and mitigate asphaltene deposition in the tubing to decrease downtime due to coiled tubing cleanouts which will reduce OPEX, 2) Support determination of a suitable reservoir pressure depletion to minimize CAPEX by implementing a pressure support project at an optimum reservoir pressure, and 3) Establish an appropriate field development strategy to produce the field at its maximum potential without jeopardizing the health of the reservoir while optimizing ultimate recovery
- Asia > Middle East > Kuwait > Ahmadi Governorate (0.94)
- North America (0.68)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Wara Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Ratawi Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Mauddud Formation (0.99)
- (8 more...)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- (2 more...)
A Success Story of Production Improvement in a Deepwater GoM Field Based on Integration of Surveillance Techniques
Gonzalez, Fabio (BP America) | Gonzalez, Doris (BP America) | Carmichael, Steve (BP America) | Stewart, Carlos (BP America) | Pietrobon, Marney (BP America) | Garzon, Francisco (BP America)
Abstract Integration of well and reservoir surveillance techniques: production measurements, reservoir fluid characterization, pressure transient analysis, production logging, relative permeability, and fractional flow are critical in understanding well and reservoir performance for an adequate well and field management specially in a high cost interventions environment. Well productivity deterioration for a specific well was identified based on production testing and well performance nodal analysis (NA). The productivity deterioration was then confirmed by means of pressure transient analysis (PTA). Standard diagnostic derivative analyses suggested that permeability decrease was the main source of performance detriment due to an apparent transmissibility reduction of 60%. Since water breakthrough took place before productivity impairment was acknowledged, the immediate reaction was to establish the hypothesis that effective permeability reduction due to relative permeability effects was the main reason for the impairment. A multilayer (ML) PTA type curve model together with fractional flow analysis did not support the relative permeability premise as the primary cause, leaving the potential for severe plugging of the reservoir rock as the predominant hypothesis. A production logging tool (PLT) was run confirming that about 60% of the completed interval was not producing at the expected levels. It was possible to separate the relative permeability effects from the plugging effects using the integrated technique described above. Relative permeability effects contributed to production impairment with an equivalent effective thickness of 14% and plugging effects impacted an equivalent effective thickness of 46%. A coiled tubing (CT) mud acid treatment was performed recovering approximately 65% of the transmissibility lost and decreasing formation skin from 16 to 9. This intervention delivered an instantaneous oil production benefit of approximately 7,000 STBOD. This analysis approach has been recommended to determine potential benefit of future intervention candidates. This paper presents an innovative approach to consider fractional flow as part of pressure transient analysis interpretation. This level of integration is not a common practice because PTA theory was developed for single phase and most of the commercial software products do not consider multiphase interpretations in analytical PTA. These limitations leave out the actual effect of relative permeability in the estimated transmissibility values.
- North America > United States (0.50)
- North America > Mexico (0.50)
Strategies to Monitor and Mitigate Asphaltene Issues in the Production System of a Gulf of Mexico Deepwater Subsea Development
Gonzalez, Doris (BP America Inc.) | Gonzalez, Fabio (BP America Inc.) | Pietrobon, Marney (BP America Inc.) | Haghshenas, Mehdi (BP America Inc.) | Shurn, Megan (BP America Inc.) | Mees, Amber (BP America Inc.) | Stewart, Carlos (BP America Inc.) | Ogugbue, Chinenye (BP America Inc.) | Duvivier, Giles (BP America Inc.)
Abstract An asphaltene threat has been identified in production wells located in a Gulf of Mexico (GOM) deepwater field. After production started from different reservoirs and the operating conditions for some of the wells reached the asphaltene precipitation onset, solid deposits were detected at different points in the production system, which caused production deferrals, disturbed the operating strategy of the field, and increased the operational expenditure. To remediate asphaltene deposition in deepwater subsea wells, a rig-less remediation costs up to $0.12 million (MM); a well intervention that requires a rig costs approximately $20 MM, and a vessel-based pumping remediation costs about $5 MM. These costs do not include the impact of production deferrals. A plan was developed to acquire and interpret the required information to properly understand and manage the asphaltene threat. The methodology includes: Acquisition of suitable downhole reservoir fluid samples for asphaltene and wax studies Characterization of the reservoir fluids in the laboratory using the latest asphaltene and wax technologies. Observation of the effect of chemicals on solids builds up during field trials Surveillance of damage near wellbore using Pressure Transient Analysis (PTA) and Multi-Rate Test (MRT) Real time monitoring of normalized nodal analysis based on frictional pressure losses. During the characterization of the reservoir fluids, asphaltenes were identified as key risk factor for successful field development. The laboratory tests showed the propensity for solids formation and confirmed that the variety of reservoir fluids had an asphaltene deposition envelope that extended from the reservoir rock to the topsides facilities. Solids collected from pigging returns, surface equipment, and failed downhole equipment confirmed the reservoir fluid's asphaltene deposition tendency. In some cases, field trials showed that increasing the concentration of asphaltene inhibitor injection resulted in increased build-up of organic deposits. PTA and MRT enable the identification of flow restrictions from the reservoir to the permanent downhole gauge location and real-time monitoring of normalized nodal analysis help to identify where the impediment to flow is located in the production system. This paper presents an integrated approach to evaluate the key elements of asphaltene risk for deepwater projects, the strategy to manage the issues during production implementation, and lay out the aspects to be considered in the mitigation of the negative impact of asphaltene thread in the field development plan.
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Reservoir Description and Dynamics > Fluid Characterization (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
A Novel Application of Standard Surveillance Techniques to Formation Damage Control by Identifying the Location of the Obstruction and Quantifying Skin Type
Gonzalez, Fabio (BP America Inc.) | Gonzalez, Doris (BP America Inc.) | Pietrobon, Marney (BP America Inc.) | Yilmaz, Timur (BP America Inc.) | Pecoraro, Jered (BP America Inc.) | Stewart, Carlos (BP America Inc.) | Giles, Duvivier (BP America Inc.)
Abstract Asphaltene is a naturally occurring constituent of crude oil consisting of high molecular weight components which in most cases are in equilibrium within the liquid phase at initial reservoir conditions. As crude oil is produced and the energy of the reservoir depletes, the equilibrium is distressed and asphaltene can precipitate out of the liquid phase. Precipitation of asphaltenes is a condition for asphaltenes deposition, but precipitation will not always result in deposition. Deposition of asphaltene has the potential to negatively impact productivity of oil wells up to the point of completely shutting in production if the problem is not identified on time and mitigated and/or treated properly. The objective of this work is to present a systematic process for data acquisition and data analysis to identify the region in the well production system where asphaltene deposition is occurring leading to a properly designed operating strategy for production and interventions. In order to identify and mitigate (or treat) the organic damage caused by asphaltene deposition near the wellbore, a methodical surveillance plan has been developed to acquire and interpret the required information at the right stage of the oil field development. The methodology consists of combining two different approaches: 1) Laboratory analysis of reservoir fluid samples using near infrared (NIR), high pressure microscope (HPM), and particle size analysis (PSA); and 2) Pressure transient analysis and multi-rate testing. This procedure has allowed us to determine when skin develops and where in the well production system between the perforations and the downhole gauge asphaltene deposition is occurring. Specifically, we have been able to integrate results of asphaltene onset pressure (AOP) with quantification of total damage and the evolution of Darcy versus non-Darcy skin to identify if damage is worsening in the formation rock or anywhere below the permanently installed downhole pressure gauge. This paper presents an innovative approach as the integration of reservoir fluid characterization; pressure transient analysis and multi-rate testing have been combined to fully assess the damage mechanism, location of the damage, and the evolution of damage as a function of cumulative production. As a result of this methodology we have been able to properly design and schedule treatments to enhance well productivity and extend the longevity of the wells without exorbitant operating expenses and unnecessary downtime. Individually, these interventions have generated economic value and greatly increased the worth of deepwater oil fields in the Gulf of Mexico through sustainable delivery.
- Europe > Norway > Norwegian Sea > Halten Terrace > PL 128 > Block 6608/10 > Norne Field > Tofte Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > PL 128 > Block 6608/10 > Norne Field > Not Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > PL 128 > Block 6608/10 > Norne Field > Ile Formation (0.99)
- (18 more...)
Summary Knowing the exact flow allocation for each controlled zone is important for well optimization and the management of an intelligent well system (IWS). For two-zone IWS producers, a broadly accepted downhole gauge configuration uses the triple-gauge system, where two gauges give the upstream-side pressure/temperature (P/T) of the two downhole control valves and one gauge gives the P/T inside tubing of the commingled fluid [Baker Hughes IWS installation (2012) and Halliburton-WellDynamics IWS installation (2012) databases]. Theoretically, this configuration gives the P/T boundary conditions between the two valves and the gauge carrier, where flow allocations can be solved numerically, on the basis of the gauge readings and control-valve settings. However, from what we have seen in the past 10 years of IWS applications, only a few have published successful application cases regarding this topic. Is this an indication that a large number of two-zone triple-gauge IWS wells are operating in the low-confidence region of the two zone's production flow allocations? In this work, a comprehensive hydraulic model has been developed to address this topic. This paper will discuss a recent application of such a model to estimate the flow allocations of an existing two-zone deepwater IWS oil producer. The well began production in 2007. A total of 1,362 daily triple-gauge data points are available for this study, where the monitored P/T data indicate that the well was flowed in multiphase conditions at downhole for a large percentage of its production life. Verification was completed by comparing the predicted flow-allocation results with this well's measured total rates and daily-allocation rates. Further comparisons of the zonal allocations, between the model calculated results vs. the zonal-reservoir deliverability-study predicted results, were also provided. These comparisons showed a good match between the predicted results, measured data, and the available reservoir-study results. Descriptions of key factors to address the accuracy of the method have been provided, including compensated differential pressure, multiphase choke model, choke-discharge coefficient, and fluid pressure/volume/temperature (PVT) behavior impact. Sun's modified multiphase choke model was proposed in this study. The authors believe it will be more suitable for downhole valve operating and multiphase-flow conditions. This case study has proven a very promising independent solution for continuous well-rate estimation, with the solution based purely on choke-pressure drops and intelligent well-valve positions. The downhole monitoring P/T is normally based on seconds, which means that intelligent well-flow allocations can be calculated in real time without installing downhole venturi flowmeters that may add completion cost. In addition, a venturi flowmeter provides a smaller ID profile for the completion strings above/below it, which is inconvenient for future potential wellbore interventions. This solution brings measurable benefits for those IWS wells with no downhole flowmeters when taking into account the time and effort spent on periodic production tests, reservoir/well deliverability studies for production allocations, and potential production loss during the production tests.
- South America (1.00)
- Asia (1.00)
- Africa (0.93)
- North America > United States > Texas (0.68)
- Asia > Brunei > Bugan Field (0.99)
- Africa > Equatorial Guinea > Gulf of Guinea > Rio Muni Basin > Okume Complex > Oveng Field > Block G > Oveng Field (0.99)
- Africa > Equatorial Guinea > Gulf of Guinea > Rio Muni Basin > Okume Complex > Oveng Field > Block G > Okume Field (0.99)
- (70 more...)
- Well Completion > Completion Monitoring Systems/Intelligent Wells (1.00)
- Well Completion > Completion Installation and Operations (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Downhole and wellsite flow metering (1.00)
Inflow Performance Identification and Zonal Rate Allocation from Commingled Production Tests in Intelligent Wells—Offshore West Africa
Saputelli, Luigi (Hess Corporation) | Oluwole, Omole (Hess Corporation) | Lissanon, Janvier (Hess Corporation) | Gonzalez, Fabio (Hess Corporation) | Chacon, Alejandro (Halliburton) | Sun, Kai (Chevron)
Abstract The main objective of a production well test is to assist in the identification of reservoir and well parameters needed for regulatory accounting, well surveillance, and asset management purposes. Interpreted information is used to drive decisions on production enhancement, operations optimization, and field-development plans. However, uncertain results may occur when wells are produced from multiple reservoirs. Currently, the industry approach is to allocate well and reservoir parameters based on known petrophysical data, offset well information, and zonal well tests. When possible, testing by difference is commonly performed to control one or more zones; however, this process may result in significant production losses with poor concluding results, especially when zonal interference is vital to a well's operating point (e.g., intelligent wells in a waterflood field). A methodology was developed to consistently identify reservoir and well-performance parameters from wells produced under commingle conditions from multiple reservoir zones by leveraging available real-time data. This methodology was successfully applied in a field located in offshore West Africa, a waterflooded field with nine intelligent wells. The methodology integrates surface well-test rates, pressures, and downhole triple-gauge data. Collected data is validated via a rigorous history calibration process of an integrated production model consisting of an analytical reservoir, well, downhole and surface chokes, and pipeline models. The calculated parameters (e.g., zonal rates, productivity index, reservoir pressure, gasoil ratio, and water cut) are the result of an error minimization between calculated variables and measured field data. This paper presents applications of this methodology for two production tests of a single dry-tree well with individually controlled reservoir zones. Benefits of the above application include a 90% reduction of the time required to perform a similar analysis, reduced uncertainty in rate allocation and reservoir parameters, and better understanding of the likely production from every reservoir zone. Because well and reservoir parameters are allocated to individual layers, the resulting rate allocation satisfies all sensor data and physical models, and therefore the uncertainty of the allocation is reduced. In addition, the application provides the basis for rate allocation to multiple zones in real time when well tests are not available.
- Asia (1.00)
- Africa (1.00)
- North America > United States > Texas (0.69)
- Africa > Equatorial Guinea > Gulf of Guinea > Rio Muni Basin > Okume Complex > Oveng Field > Block G > Oveng Field (0.99)
- Africa > Equatorial Guinea > Gulf of Guinea > Rio Muni Basin > Okume Complex > Oveng Field > Block G > Okume Field (0.99)
- Africa > Equatorial Guinea > Gulf of Guinea > Rio Muni Basin > Okume Complex > Oveng Field > Block G > Okume Complex (0.99)
- (69 more...)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Well performance, inflow performance (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
Abstract Knowing the exact flow allocation for each controlled zone is important for well optimization and the management of an intelligent well system (IWS). For two-zone IWS producers, a broadly accepted downhole gauge configuration uses the triple-gauge system, where two gauges give the upstream side pressure/temperature (P/T) of the two downhole control valves, and one gauge gives the P/T inside tubing of the commingled fluid. Theoretically, this configuration gives the P/T boundary conditions between the two valves and the gauge carrier, where flow allocations can be solved numerically, based on the gauge readings and control valve settings. However, from what we have seen in the past 10 years of IWS applications, only a few have successfully published application cases regarding this topic. Is this an indication that a large number of two-zone triple-gauge IWS wells are operating in the low-confidence region of the two zone's production flow allocations? In this work, a comprehensive hydraulic model has been developed to address this topic. This paper will discuss a recent application of such a model to estimate the flow allocations of an existing two-zone deep-water IWS oil producer. The well began production in 2007. A total of 1,362 daily triple gauge data points are available for this study, where the monitored P/T data indicates that the well was flowed in multiphase conditions at downhole for a large percent of its production life. Verification was completed by comparing the predicted flow allocation results with this well's measured total rates and daily allocation rates. Further comparisons of the zonal allocations, between the model calculated results versus the zonal reservoir deliverability study predicted results, were also provided. These comparisons showed an excellent match between the predicted results, measured data, and the available reservoir study results. Descriptions of key factors to address the accuracy of the method have been provided, including compensated differential pressure, multiphase choke model, choke discharged coefficient, and fluid pressure-volume-temperature (PVT) behavior impact. A modified multiphase choke model was proposed in this study. The authors believe it will be more suitable for downhole valve operating and multiphase flow conditions. This case study has proven a very promising independent solution for continuous well rates estimation, with the solution based purely on choke pressure drops and intelligent well valve positions. The downhole monitoring P/T is normally based on seconds, which means that intelligent well flow allocations can be calculated in real-time without installing downhole venturi flow meters that may jeopardize well profitability and integrity. This solution brings measurable benefits for those IWS wells with no downhole flow meters, when taking into account the time and effort spent on periodic production tests, reservoir/well deliverability studies for production allocations, and potential production loss during the production tests.
- Asia (0.93)
- North America > United States (0.68)
- Well Completion > Completion Monitoring Systems/Intelligent Wells > Real-time optimization (1.00)
- Well Completion > Completion Monitoring Systems/Intelligent Wells > Downhole sensors & control equipment (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- (2 more...)
Real-time Production Optimization in the Okume Complex Field, Offshore Equatorial Guinea
Omole, Wole (Hess Corporation) | Saputelli, Luigi (Hess Corporation) | Lissanon, Janvier (Hess Corporation) | Nnaji, Obiageli (Hess Corporation) | Gonzalez, Fabio (Hess Corporation) | Wachel, Georgie (Hess Corporation) | Boles, Kim (Hess Corporation) | Leon, Edicson (Hess Corporation) | Parekh, Bimal (Hess Corporation) | Nguema, Nicolas (Hess Corporation) | Borges, Jesus (Petroleum Experts) | Hadjipieris, Pieris (Petroleum Experts)
Abstract Efficient oilfield asset management requires the effective use of real-time data, model updates, and optimization of control variables to produce the most favorable choices However, the orchestration of disciplines, workflow tools and available data represents critical issues in the oil industry. In many cases, the engineer may not focus on high-impact tasks nor generate added-value opportunities. Instead, the engineer's attention is diverted to collect, manipulate and create data charts. Data collection and validation, as well as model validation and updates, are repetitive tasks that may be automated under certain conditions to relieve engineers from low- value-added tasks. Real-time production optimization (RTPO) is one component of the Digital Oil Field (DOF) that aims to solve these issues. This paper focuses on the implementation of an RTPO system in the Okume Complex field in Offshore Equatorial Guinea. Two main challenges in this field include continuously allocating gaslift in frequently changing field conditions while minimizing production losses as well as understanding and maximizing the field production plateau. A commercial tool was used to demonstrate the value of RTPO. The implemented project supports the automation of standard workflows within the asset. The project proved several hypotheses concerning the streamlining of data capture, discipline interaction and model sustainability. Data availability and model readiness resulted as key factors from the fast and proficient implementation of the tool. The implementation of the project reduced the time requirement for test data gathering, validating, and model updating by more than 70%. The intelligent wells achieved continuous zonal allocation while minimizing the risks of crossflow. According to the results of this work, the asset is now able to adjust gaslift settings on a daily basis for optimizing production between 1.0% and 5.1% daily. This paper presents a summary of the benefits during pilot implementation, current project status, and the next steps.
- Africa > Equatorial Guinea > Gulf of Guinea (0.72)
- North America > United States > Texas (0.68)
- Africa > Equatorial Guinea > Gulf of Guinea > Rio Muni Basin > Okume Complex > Oveng Field > Block G > Oveng Field (0.99)
- Africa > Equatorial Guinea > Gulf of Guinea > Rio Muni Basin > Okume Complex > Oveng Field > Block G > Okume Field (0.99)
- Africa > Equatorial Guinea > Gulf of Guinea > Rio Muni Basin > Okume Complex > Oveng Field > Block G > Okume Complex (0.99)
- (71 more...)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Well performance, inflow performance (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well Operations and Optimization (1.00)
- (5 more...)
Summary Cased-hole neutron logging has been in use for many years and is often used to monitor gas movement in reservoirs behind pipe. This works well in high-porosity reservoirs but is rarely successful in low-porosity reservoirs. In Colombia, there are high-flow-rate reservoirs with significant permeability but low porosity [5 to 6 porosity units (p.u.)]. The challenge was to monitor gas-cap expansion, fluid movement owing to re-injection, and voidage. At the same time, the objective was to identify low gas/oil ratio (GOR) intervals behind pipe for possible recompletion. A number of different examples illustrate both the technique and the economic benefit of the monitoring program. Many of these wells contributed significant additional oil from bypassed zones that were initially thought to be dry gas. In some wells, the instantaneous incremental production was over 10,000 BOPD from a single recompletion. Gas-cap monitoring in very-low-porosity reservoirs in Colombia proved to be not only feasible, but also extremely profitable by differentiating dry-gas zones from low-GOR zones. Introduction - Cusiana Field, Colombia Cusiana is a field in Colombia (Fig. 1) that produces high rates of oil and gas from sandstone formations in the Andes foothills. Tectonic evolution of the area dates back to an early Paleozoic rifting period, forming grabens where a thick sequence of sediments was deposited. The Llanos (the plains area east of the Andes in Colombia) was an extensional subsidence basin in the Triassic and early Cretaceous periods, becoming a passive subsidence basin in the late Cretaceous period (Fig. 2). Tertiary, Cretaceous, and Paleozoic silico-clastic sedimentary sequences overlie the pre-Cambric basement consisting of crystalline and metamorphic rocks. The maximum sedimentary thickness reaches 12 000 m. Exploration in this basin has focused on structural traps in the foothills and platform areas where the major discoveries have been made. The Cusiana volatile oil field is associated with a complex thrust anticline and overturned structures that exist along the foothills zone. The productive formations in Cusiana (Mirador, Barco, and Guadalupe) have low formation porosities, but they have relatively wide permeability ranges. The Mirador has average reservoir porosities in the 5 to 6 p.u. range, with very short intervals of higher porosities up to 10 p.u. and permeabilities up to 1,000 md. The Barco formation has porosities from 5 to 10 p.u. and permeabilities from 1 to 300 md. The Guadalupe has 6 to 15 p.u. and permeabilities of approximately 200 md. The wells drilled into these formations produce from 5,000 to 25,000 BOPD. The generalized stratigraphic column in Fig. 3 shows the productive formations and their ages. The map in Fig. 4 shows the field structure, which trends northeast/ southwest. Additionally, the well locations surveyed are represented. Monitoring Tool Historically, neutron porosity has been computed from a ratio of the near- to far-count rates. Generic neutron tools have a chemical nuclear source that emits high levels of neutrons to two detectors. Using the ratio of the near-to-far counts from these detectors has the advantage of a robust calibration repeatability and accuracy. This method, however, tends to mask the sensitivity of the source detector count-rate measurements to many effects, including gas and certain borehole effects. It was decided to use a new model neutron tool with four sets of detectors, in an array with a downhole neutron accelerator, as a neutron source to monitor gas movement in Cusiana. This tool is called the Accelerator Porosity Sonde (APS, Fig. 5). It was expected that the increased source-to-detector spacing would give good results in this difficult, low porosity environment. The array of source-to-detector spacings was designed with Monte Carlo simulations to optimize its effectiveness. The detectors are eccentered (rather than centered in normal neutron tools) to optimize their responses and minimize environmental effects. It was also expected that the relatively higher neutron source strength from the downhole neutron accelerator would give improved sensitivity to gas. Using the individual count rates from the near and far epithermal detectors in a qualitative overlay gives a superb sensitivity to gas in the formation, even at very low formation porosities. A formation sigma was also available from the APS tool. The formation and injected waters in Cusiana and Buenos Aires are very fresh, and sigma is not an effective water-to-hydrocarbon indicator. The porosity range in the Mirador and Barco formations is too low to use sigma as a reliable gas discriminator. The difference between 100% gas and 100% oil at this porosity level is 0.84 capture units. Why Does This Work? The far epithermal detector reads much deeper into the formation than the near epithermal detector because of the longer source-to-detector spacing. The near epithermal detector gives shallow readings and is not much affected by the deeper formation. In gas zones, there are fewer hydrogen atoms to slow down the neutrons, so there are many neutrons that reach the far detector. The near epithermal detector is less affected by this gas. In general, most neutron tools are affected by gas in a similar manner; however, in contrast to the use of more stable ratios for a quantitative porosity, the count-rate overlay approach with the different epithermal detector spacing is more sensitive to gas and, as a result, an excellent indicator of gas in the reservoir - even through casing. The technique is to overlay near and far epithermal count rates in a liquid-bearing interval, then look for gas when the far detector count rate increases faster than the near-count rate. The approach is even more robust when there are in-gauge shales that can also be used as a low-count rate endpoint. Separation in gas intervals or intervals with gas in the annulus is very pronounced. The tool count-rate results were not compared to other generic neutron tools to determine if a less sophisticated measurement may have worked with only thermal neutron count rates in low-porosity reservoirs. The authors do not know of any other monitoring projects that use the APS.
- South America > Argentina > Buenos Aires F.D. > Buenos Aires (0.30)
- South America > Colombia > Casanare Department (0.25)
- Europe > Norway > Norwegian Sea (0.24)
- Geology > Structural Geology > Tectonics > Compressional Tectonics > Fold and Thrust Belt (0.74)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.54)
- South America > Colombia > Casanare Department > Llanos Basin > Cusiana Field > Mirador Formation (0.99)
- South America > Colombia > Llanos Basin > Mirador Formation (0.94)
- South America > Colombia > Barco Formation (0.94)