Using the upgraded capabilities of the perforation flow laboratory, and after some trial and error, tests were successfully conducted designed to compare zinc and steel-cased big hole (BH) shaped charges at bottomhole conditions. In the past, conducting perforation performance tests that included wellbore control were limited to matching reservoir pressures up to 5,000 psi. These tests were conducted at conditions representative of a Gulf of Mexico (GOM) reservoir exhibiting 17,200 psi overburden stress, 9,100 psi pore pressure, and a temperature of 210°F. Completion plans include setting the wellbore pressure at 10,550 psi before perforating to create a static overbalance of 1,450 psi. Aligned with American Petroleum Institute Recommended Practice 19B (2006) Section 4 (Rev. 2014), the tests were conducted to closely match the perforating portion of the completion design in the oil-producing field to provide an effective physical simulation. The outcome provides useful perforation performance data, including flow into and out of the perforation.
Many design modifications from previous ambient, limited pressure Section 4 tests were necessary to successfully conduct the tests at the higher GOM reservoir pressure and 210°F. This paper discusses the difficulties encountered during testing and how workable solutions were achieved to perform such tests. Reinforcing the integrity of the soft, producing formation analog core without reducing the effective stress was the most significant challenge encountered during this study. Sustaining steady flow at pressures higher than the limits of the available high-accuracy pressure transducers and flow meters also required a new approach. The net result of this effort revealed that penetration depth differed less that previously assumed between the zinc-cased charge and the steel-cased charge at the experimental conditions and setup used in the tests.
The development of perforation testing laboratories has allowed the capability to shoot any shaped charge in a simulated wellbore environment at elevated temperatures and high pressures, matching virtually any reservoir in the world.
The oil market is in a state of rapid change due to the decreasing oil price, with an urgent need for radical cost reduction of existing development solutions. For the subsea boosting market this comes on top of a historically slow market adoption of subsea processing technology in general. Now, with the new market situation, the incentives for solutions that can increase recovery are strengthened and should become more important to Operators for both Greenfield and Brownfield. The opportunity for subsea process solutions and in particular subsea boosting solutions to become a standard in the industry is right now. To realize this opportunity there is a significant need for change in the knowledge and cost of subsea boosting solutions, to strengthen the business case and thereby grow the market for subsea boosting
Many factors will contribute to this change, but this paper will focus particularly on innovative technical solutions that will simplify existing systems, prepare for true standardization and by this significantly reduce size, weight and cost compared to existing designs. Furthermore, introducing innovative technologies supports simplified installation and intervention as well as deepwater and long step-out developments. All of this is possible without introducing big technology leaps or compromising the reliability of the overall solution.
The paper will provide case studies demonstrating cost savings including size / weight comparisons of conventional and new solutions, as well as dives into certain technology elements with proven results.
Talabi, O. A. (Schlumberger) | Nitura, J. T. (Schlumberger) | Biniwale, S. S. (Schlumberger) | Ramdzani, R. (Schlumberger) | Salim, M. M. (Schlumberger) | Ahmad, A. (Schlumberger) | Som, M. K. M. (Schlumberger)
Declining production and dwindling reserves are a main challenge for many mature fields. For such fields rejuvenation projects are common and may include the use of an integrated operations (IO) or digital oilfield (DOF) system as an asset management decision support tool. Forecasting future production in the short-term is a key part of the asset decision making process. However, in traditional practice with multiple locations and teams modeling in silos, not all production system interactions are considered for short-term decision making. In many cases, short-term production (STP) forecasting is done using a simplistic analytical approach, in which a decline rate is used to forecast, and the forecast is adjusted on a monthly basis. Many assumptions are made, which limits realistic prediction of field potential by ignoring reservoir-network interactions. This can result in large deviations from actual production in fields with secondary or tertiary recovery and preclude the engineers understanding what is actually happening in their production system. The objective of this work was to provide a streamlined methodology for making short-term forecasts using integrated models that help engineers better understand the interactions between different parts of the production system. This would provide a proactive approach to managing the production.
To recognize the true potential of the asset, an "integrated asset model" is introduced as part of a DOF or IO project with state-of-the-art modeling techniques that models the asset as a whole unit rather than isolated silos. The integrated asset model framework used in this work includes eight dynamic reservoir models coupled to a production network model and a complex process facilities model. Although such an integrated model is expected to provide improved forecasts, it is can also be time consuming to keep the model updated. To mitigate this, the integrated asset model framework is also supported by an underlying system that keeps the model up-to-date by incorporating the latest production data to reflect current reservoir/production changes making it "live" and always ready for predictions. The model has been modified to support detailed modeling of events and activities.
For STP, the workflow automates calculation of well and field potentials as well as planned/unscheduled deferments based on the activity plan and expected production. In addition to making short-term forecasts, the model can also be used to validate production enhancement activities before they are approved and implemented. In this way, the impact of these production enhancement activities can be assessed, not only for the single well, but also for the entire production system.
Some of the expected benefits and value gains from this approach are – Improved confidence/accuracy in the forecasts and effectiveness of proposed enhancements. Systematic and streamlined process for short-term forecasting and validating proposed enhancements. Additional information and increased confidence in estimates used to support cost of production enhancements. Identification of the impact of planned short-term activities and production enhancements on the entire asset. Capability to run "what-if" scenarios to improve the effectiveness of planned activities and enhancements. Increased collaboration between different engineers, models and domains for better decision making.
Improved confidence/accuracy in the forecasts and effectiveness of proposed enhancements.
Systematic and streamlined process for short-term forecasting and validating proposed enhancements.
Additional information and increased confidence in estimates used to support cost of production enhancements.
Identification of the impact of planned short-term activities and production enhancements on the entire asset.
Capability to run "what-if" scenarios to improve the effectiveness of planned activities and enhancements.
Increased collaboration between different engineers, models and domains for better decision making.
This novel approach modernizes perspective for short-term forecasting and reveals that an asset's true production potential can best be predicted using an integrated modeling approach.
Chemical flooding is one of the challenging EOR methods to improve the oil recovery. The objective of this work is to examine a systematic approach for upscaling Alkaline Surfactant Polymer (ASP) coreflood data to field scale and design the single well chemical tracer (SWCT) test. Appropriate upscaling can help to determine the effect of crucial parameters on process mechanisms and oil recovery. Besides, uncertainty assessment should be conducted thoroughly to evaluate the impact of key parameters.
In this paper, a robust approach for modeling the ASP flood from core to reservoir scale including the data uncertainty would be presented. Experimental work was aimed to screen and select the suitable chemicals for implementation in the field. Coreflood tests include ASP flood with and without polymer chase with the objective to evaluate the effectiveness of chemical flood and sweep efficiency. Sensitivity analysis by response surface methodology (RSM) would help to find the crucial parameters during the history matching of coreflood tests and reservoir modeling for ASP implementation.
Coreflood modeling was performed to represent the flow behavior of lab tests and investigate the mechanisms through the experimental efforts. Assisted history matching of the coreflood test was carried out to incorporate waterflood and chemical flood processes. Some variables such as relative permeability characteristics, trapping number, adsorption, and residual resistance factor were included as matching parameters. The next step was to upscale the model from core scale to reservoir scale by an appropriate method. Velocity and pressure were preserved during the scaling procedure. The parameters obtained from scaling exercise were used for SWCT design and full field model. Thus, radial models were used to describe and improve the design of SWCT tests for candidate wells. The next step was to evaluate the ASP flood on reservoir model. Sensitivity analysis was conducted on key parameters e.g. adsorption, injector-producer spacing, residual oil reduction by chemical, and ASP slug size to identify the impact of these parameters on oil recovery. RSM was applied to develop a suitable proxy model based on the results of sensitivity study. The proxy model can be used to find the optimum well spacing and slug size for field implementation.
Appropriate technique of chemical flood modeling is presented in this work. Moreover, upscaling of lab data to reservoir scale for pilot design and evaluation of ASP flood on reservoir scale by considering how to address risks and uncertainties are other outcomes of this work.
Al-Daihani, Eisa (Kuwait Oil Company) | Nandi, Arun Kumar (Kuwait Oil Company) | Al-Awadhi, Sherif (Kuwait Oil Company) | Matar, Maqhim Bander (Kuwait Oil Company) | Razaa, Syed Mohammad (Kuwait Oil Company)
There are many learning tools available to fill competency gaps of an employee. The common learning tools are classroom courses, workshops, internal on job Training, external on job training with international companies, NOCs and Service Companies, e learning and other learning activities like attending conferences, forums, symposiums etc. However, the most cost effective tool is E-learning. This helps to fill the technical knowledge gap of the participant with flexibility and conveniently. Most of the E-Learning topics include multimedia for better deliverability. It is the most popular learning tool among new generation because they are technology oriented.
The present paper focusses on a pilot project where an attempt has been made to strengthen the E-learning tool through Action learning. The pilot project needed involvement of Coaches and Discipline Experts (DEs) besides candidates selected as participants of E-learning. Accordingly, as a case study, 10 employees (batch of same job family) with same topic were chosen to participate in the pilot project. Few discipline experts and coaches were also involved related to the course content of the E-learning session. A half-day session was organized with online access of the E-learning topic to all participants and DEs and coaches. After going through the entire topic, a group discussion was held and followed by question answer (QA) session.
As E-learning is a kind of self-learning; the effectiveness of the learning tool was dependent on the seriousness of an individual employee. Conventional assignment of E-learning topic and its implementation was helpful in filling the competency gap in the order of 60 to 70% of the course contents or even lower. However, after making E-Learning in to Action Learning through pilot project, the competency gap filling has been achieved up to 100%.
The implementation of E-learning through Action Learning has developed an interest, value addition and fulfillment of competency gaps of individual employees. This will result in fast track development of technical competence and thus help to achieve the group's business needs and company's goal.
Omar, M Mizuar (PETRONAS Carigali Brunei Ltd) | Rasli, M Faiz (PETRONAS Carigali Brunei Ltd) | Paimin, M Razali (CANAM Brunei Oil Ltd) | Maulana, Herry (CANAM Brunei Oil Ltd) | Ghosh, Amitava (Baker Hughes) | Abidin, M Zyden Su'if B Zainal (Brunei National Petroleum Company)
Pore pressure prediction and geomechanical modelling play a very important role in well planning and is one of the many challenges facing the oil industry today, as exploration focus worldwide is moving more and more into the deep-water environment. Pressure related problems in deepwater wells are mainly associated with narrow operating window resulting in severe well control incidents, sometimes even leading to early abandonment. A better understanding of the prevalent pore pressure regimes in terms of generating mechanisms along with pressure maintenance and dissipation through geologic time offers invaluable insight and perception about these challenges and also on our ability to predict and mitigate or minimize them. Borehole instability related problems like excessive wellbore breakout can result hole cleaning issues, stuck pipe, setting casing earlier or potentially losing the wellbore. It is important to analyze these challenges and develop an understanding of the same, prior to drilling so that, various plans and mitigation systems can be put in place.
A substantial amount of non-productive time (NPT) was associated during the initial phases of drilling campaigns in the Brunei deepwater. Accurate mud weight window prediction using regional scale pore pressure prediction and geomechanical modeling clearly demonstrated a significant reduction in nonproductive times over the different phases of drilling campaigns till date. This also includes a regular update or refinement of the model as soon as new data or information becomes available.
This paper presents some of the methodologies used during well planning and construction of deepwater and ultra-deepwater wells. It also discusses the work refinement throughout each drilling campaigns, which resulted in improvement on geological and geomechanical model. It is imperative to note that the intent is to document and share experiences and lessons learned in Brunei deepwater wells within the industry. This would enable the execution workflow and well design to be continuously improved for a safe and cost-efficient delivery of the wells.
Gas reservoirs often contain a proportion amount of naturally occurring CO2, ranging from a few percent up to 70% by volume. A carbonate gas field located in offshore Sarawak, eastern Malaysia has a very high concentration of CO2 and expected to be a world pioneer offshore CO2 storage in high CO2 field with the accumulated amount of 70 % mole of the gas in place. Carbon dioxide from the gas field is removed from the gas production stream in a central gas processing facility and then the CO2 is compressed, transported and stored underground in the carbonate reef reservoir of the same gas field. This study details the geochemical effects of CO2 injection into the field as part of the proposed field development. In this study, we ran a two-dimensional reactive transport models using TOUGHREACT. The model was run for 300 years at the temperature of 140°C and pressure of 352 bars. The CO2 was injected for 30 years below gas water contact (GWC) in the aquifer. The modelling results shows that the overall geochemical alterations of injected CO2 into solid phase are minimal and is confined to the region below the original gas water contact with the minimal additional impact on injectivity. This is due to the dry-out formation vicinity to the injection well that lead to the small amount of salt precipitation. These findings demonstrate the importance of geochemical reactions study when injecting CO2 into high CO2 gas field at high pressure and temperature.
An aqueous-based linear gel composition comprising diutan gum and an environmentally acceptable stabilizer has been developed for gravel packing applications. This aqueous-based gel works at elevated temperatures greater than 300°F. The rheological properties of these linear gels are particularly useful in gravel packing operations that involve shunt tubes. This paper presents laboratory studies that demonstrate the gel's thermal stability, rheological properties, minimal formation damage characteristics, and suitability for gravel packing operations.
Linear diutan gels exhibit excellent sand-suspension characteristics, even when they have relatively low viscosity, because of their hyper-branched structure. However, their use at temperatures greater than 270°F can be challenging because of limited thermal stability. A new fluid composition that comprises a biodegradable, environmentally acceptable gel stabilizer was developed to address this issue. Thermal stability and rheological properties were studied using a high-pressure/high-temperature (HP/HT) concentric cylinder viscometer at elevated temperatures and various shear rates between 5 and 1021 s−1. The sand-suspension characteristic was studied using a HP/HT autoclave. Formation damage characteristics caused by fluid invasion were studied by measuring regain permeability after coreflooding.
The results show the thermal stability of linear diutan gel improved from 270 to 310°F when the gel stabilizer was added. This fluid was stable up to 4 hours and exhibited excellent shear-rehealing properties at 310°F. The fluid rheology profile at various shear rates is in accordance with the criteria necessary for gravel packing operations that use shunt tubes. The fluid could suspend proppant/sand for 1 hour at 310°F with less than 20% settling. The gel stabilizer helped to improve thermal stability and sand-suspension characteristics by scavenging oxygen dissolved in the fluid and quenching the radicals generated at higher temperatures. The fluid was compatible with completion brine, crude oil, and oil-based drilling mud. Therefore, it could be used in nonaqueous fluid-pack completions. It showed more than 90% regain permeability, which suggests a clean break of gelling agent and low damage to the formation rock.
The good thermal stability and sand-suspension properties of the fluid system using the biodegradable, environmentally acceptable gel stabilizer makes it a good candidate for gravel packing operations in HP/HT reservoirs. The low-residue fluid property helps ensure economical production rates.
The Middle Eastern formations E & K are aquifers which are commonly problematic due to their corrosive characteristics, have been known to directly cause downhole casing completion leaks, and hence require careful risk assessment. If severe corrosion is not detected early then related leaking completions can lead to water from these upper formations cross flowing down into producing reservoirs with results being economic loss due to reservoir damage and/or direct loss of production. Environmental impacts of hydrocarbons leaking into shallow aquifers are an obvious risk of a leaking casing. The worst-case scenario is when production fluids, particularly methane and H2S, enter these formations via near-surface casing leaks and migrate to the surface where the potential for catastrophe is highest. This investigation explores causes and effects of severe external well casings corrosion in an oil-producing brownfield in the Middle East.
This research utilizes advanced corrosion monitoring technology, capable of measuring total wall thickness of concentric casings, which were logged in adjacent wells within a one-half mile radius. An important part of the well assessment strategy also includes examining historical drilling and cementing of several other completions in the same field to categorize the probability of integrity failure due to external corrosion.
Observations include establishing correlations between these lost circulation formations and measured external casings corrosion wall loss. The corrosive characteristics and impact of these dynamic, near-surface aquifers is also discussed to establish the root cause of external casing leaks. The objective of this study is to share these lessons-learned and develop a strategy for recognizing, mitigating, and/or avoiding similar well integrity conditions. By instituting a well-to-well pattern recognition classification of known problematic wells, promoting an enhanced corrosion surveillance frequencies.
Keshavarz, Alireza (Australian School of Petroleum, The University of Adelaide) | Johnson, Ray (Australian School of Petroleum, The University of Adelaide) | Carageorgos, Themis (Australian School of Petroleum, The University of Adelaide) | Bedrikovetsky, Pavel (Australian School of Petroleum, The University of Adelaide) | Badalyan, Alexander (Australian School of Petroleum, The University of Adelaide)
The technology of injecting micro-sized proppant particles along with fracturing fluid is proposed to improve the conductivity of naturally fracture systems (e.g., cleats, natural fractures) in stress sensitive reservoirs, by placing graded particles in a larger, preserved stimulated reservoir volume around the induced hydraulical fracture. One of the main parameters determining the efficiency of the proposed technology is the concentration of placed proppant particles in the fracture systems. A laboratory study has been conducted to evaluate the effect of placed proppant concentration on coal permeability enhancement using a one-dimensional linear injection of micro-sized proppant into coal core and varying effective stress. Permeability values are measured for different concentrations of placed particles as a function of effective stress. The results show that there is an optimum concentration of placed particles for which the cleat system permeability reaches a maximum and permeability enhancement is more sensitive to concentration of placed proppant at higher than lower effective stress. The experimental results show maximum permeability enhancement of about 20% for an optimum concentration of placed particles at 490 psi effective stress. Permeability enhancement by 3.2 folds is observed at elevated effective stress of 950 psi. Finally, the paper proposes a field application strategy to apply graded particle injection in field case study.