Gupta, Shilpi (Schlumberger) | Pandey, Arun (Schlumberger) | Ogra, Konark (Schlumberger) | Sinha, Ravi (Schlumberger) | Chandra, Yogesh (ONGC) | Singh, PP (ONGC) | Koushik, YD (ONGC) | Verma, Vibhor (Schlumberger) | Chaudhary, Sunil (Oil & Natural Gas Corp. Ltd.)
Production logging has been traditionally used for zonal quantification of layers for identification of most obvious workover for water shut off, acid wash or reperforation candidate identification. The basic sensors help in making some of the critical decisions for immediate gain in oil production or reduction in water cut. However, this technology can be used in a non standard format for various purposes including multilayer testing to obtain layer wise permeability and skin factor using pressure and flow rate transient data acquired with production logging tools. This is very crucial and complements the present wellbore flow phenomenon to better understand relative zonal performance of well at any stage of its production. In addition, production logging along with the pulsed neutron technique is very crucial to evaluate the complete wellbore phenomenon, understand some of the behind the production string fluid flow behaviors. Another major concern in low flow rate wells is recirculation, causing fall back of heavier water phase while lighter phase like oil and gas move upwards. This well bore phenomenon renders the quantification from production logging string, and this in extension also prevents any comprehensive workover decisions on the well because of the risk involved. Oil rate computation from hydrocarbon bubble rates becomes very critical in such scenarios to bring out the most optimal results and enhance confidence in workover decisions. Another key concern in any reservoir is to evaluate the productivity Index; this is even more critical once the field is on production. It is essential to determine the performance of various commingled layers and reform the Injector producer strategy for pressure support or immediate workover. Selective Inflow performance is a technique used to identify the Productivity index of various layers in a commingled situation. This paper elaborates on various non conventional uses of production logging from the western offshore India.
Brown field management has been a key focus in the western offshore region. Over the last decade cased hole production logging for evaluation of reservoir phenomenon has been the backbone of workover operation in western offshore India. Besides the usual operations production logging has been pivotal in determining various important parameters for field development. Various unconventional uses require understanding of the tool physics and limitation. Advanced generation of production logging tools not only provide additional information in terms of wellbore flow fractions, slippage velocities and complex flow regimes but their basic outputs can also be utilized in variety of applications for reservoir evaluation and wellbore flow monitoring. Following sections describe several case studies describing unconventional usage of production logging outcomes.
Unconventional Applications of Production Logging
Case Study 1: Selective Inflow Performance
Field wise production logging has always been an excellent source to evaluate the open hole results and suggest some immediate workover to optimise the production. Selective Inflow performance is new variation in the already existing technique used to identify the Productivity index of various layers in a commingled situation. This operation can provide us with the openhole flow potential of the well and thus help in mapping the flow profile in the reservoir. A multichoke production logging survey usually covering two to three choke sizes is performed and flow profiling for each survey is done.
The time taken to safely optimise a reservoir produced by artificial lift can be measured in weeks or months.
Typically the well by well process is as follows:
• Well testing
• Amalgamation of the well test data with down hole gauge and ESP controller data
• Analysis of the data to find the existing operation conditions
• Analysis of the ESP pump curve operating point and optimisation limitations
• Sensitivity studies in software to assess the optimum frequency and WHP
• Notification for the field operations to action the changes
• Further well tests to verify the new production data.
• Analysis of the data to ensure the ESP and well are running optimally and safely at the new set points
New technology enables this process to be performed in real time across the entire reservoir or field, significantly shortening the time to increased production and enabling real time reservoir management.
Each artificially lifted well in the reservoir was equipped with an intelligent data processing device programmed with a real time model of the well. The processors were linked to a central access point where the operation of field could be remotely viewed in real time.
Each well's processor was provided with a target bottom hole flowing pressure to enable the optimum production of the reservoir. The real time system automatically compared the desired target drawdown values with the capability of the pumping system installed in each well, and automatically suggested the optimum operating frequency and well head pressure to achieve the target. Where the lift system was not capable of producing to the target bottom hole pressure, a larger pump was automatically recommended. As production conditions change the system adapted its recommended operating points to compensate and maintain target production.
This paper discusses three case studies where real time optimisation and diagnosis lead to improved production from the reservoir.
Alomair, Osamah Ali (Kuwait University) | Alarouj, Mutlaq Abdullah (Kuwait University) | Althenayyan, Abdullah Ahmed (Kuwait University) | Al Saleh, Anwar Hassan (Kuwait University) | Almohammad, Humoud (Kuwait University) | Altahoo, Younes (Kuwait University) | Alhaidar, Yousef (Kuwait University) | Al Ansari, Sara Ebrahem (Kuwait University) | Alshammari, Yousif (Kuwait University)
Thermal recovery methods have the objective of accelerating hydrocarbon recovery by raising the temperature of the formation and reducing hydrocarbon viscosities. Thermal recovery involves several well-known processes such as steam injection, in situ combustion, steam assisted gravity drainage (SAGD), and a more recent technique that consists of heating the reservoir with electrical energy. The most common thermal method is steam injection. However, some difficulties occurs with steam injection includes; water availability, the cost of water vaporization process, and how to keep steam temperature above the condensation temperature at reservoir conditions. Also it is limited to relatively shallow, thick, permeable, and homogenous sand reservoirs that are located onshore.
In this project three unconventional thermal approaches were developed in laboratory scale to improve the recovery of heavy oil. Those methods are; electrical resistant electrodes, electromagnetic inductors, and microwaves. Designing and experimenting were prepared using low cost material to achieve the success of the new approaches. In the electrical resistance approach, a potential difference was applied between two electrodes; one act as anode and the other one as a cathode. A sufficient heat has been introduced between the electrodes, which improved the oil recovery by adding a maximum of 21% additional recovery to the primary recovery. For the electromagnetic induction, a coil has been wrapped around a core through which the introduced heat was transmitted to the fluid inside and hence increasing the oil recovery by a maximum of 34%. As for the microwave method, microwaves were applied on the core to vibrate water molecules. These microwaves were created and applied by using normal microwave oven, where the waves were transmitted from the source, and reflected inside an isolating body to prevent any wave leakage. The molecules movement resulted in heat generation and thus a reduction in the oil viscosity. The conducted test revealed an increase of 30% in the oil recovery which varies according to the operating power. Finally, economical comparison between the proposed methods was conducted. The three methods were compared by combining recovery and power consumption. Average power consumption per unit production for electromagnetic induction, Electrical Resistance, and microwave were 39, 2570, and 3.775 watt.hr/cc, respectively. The comparison revealed that the Microwave Heating is the most economical choice followed by electromagnetic induction and finally the electrical resistance heating.
Nghiem, Long X. (Computer Modelling Group Ltd.) | Mirzabozorg, Arash (University of Calgary) | Chen, Zhangxin John (University of Calgary) | Hajizadeh, Yasin (Computer Modelling Group Ltd.) | Yang, Chaodong (Computer Modelling Group Inc.)
History matching of reservoir flow models based only on production data may not reveal deficiencies that affect future predictions. Incorporating saturation and temperature profile data that come from 4D seismic surveys in the history matching process can reduce the uncertainty of reservoir models for the prediction stage. We constructed a field reservoir model from which production history, saturation and temperature profile history were obtained. We started the history matching process with a base reservoir model, the petro-physical properties of which were substantially different than those of the field reservoir model. We propose a new methodology for matching the fluid and temperature profiles by adjusting reservoir petro-physical properties. In this methodology, some grid blocks in a reservoir model were selected judiciously to capture the overall saturation and temperature distribution profiles. In addition to well production data, we included the saturation and temperature profiles at these grid blocks as extra objective functions during the history matching process. The DECE optimization is used to reduce the objective function. We applied this method in a Steam Assisted Gravity Drainage (SAGD) process and matched the saturation and temperature profiles with an average error of less than 2%.
Excessive water production from unwanted zones in oil producing wells is one of the major challenges faced by the oil industry. The applicability of organically crosslinked polymer (OCP) systems as sealants for water shutoff treatments in temperatures up to 350°F is well documented. However, their effectiveness at temperatures above 350°F has not been evaluated. This paper presents experimental data from using an OCP system for water shutoff treatments at 400°F.
At temperatures around 400°F, crosslinking is expected to happen faster and can lead to premature gelation of the recipe before the entire treatment is in place. Thus, controlling the gelation time at such temperatures is extremely crucial. Optimizing the amount of retarder is essential to provide adequate time for placement of the treatment fluid. This paper provides gelation time data at temperatures between 350 and 400°F with different amounts of retarder. With an optimum amount of retarder, the OCP showed a gelation time of 1 hr 20 min.
This paper also describes the experimental setup used to study and determine the long-term stability of the OCP system at 400°F. Sand packs measuring 1-ft long were used for the test to simulate formation conditions. Once the optimized OCP recipe was gelled inside the sand pack, measurements were taken by gradually applying incremental differential pressure (?P) to evaluate the sealant at temperature, as well as the threshold ?P the system could withstand. Even after one month at 400°F, the OCP recipe was able to sustain a ?P of 950 psi over the sand pack.
The data indicates the applicability of this system as an effective conformance product to shut off water-producing zones over an extended period of time at 400°F.
The success of recent applications in underbalanced drilling (UBD) and managed pressure drilling (MPD) has accelerated the development of technology in order to optimize drilling operations. The increased number of depleted reservoirs and the necessity for reducing formation damage has also increased the need to apply UBD/MPD to such candidate fields. Several methods used the latest mechanistic multiphase flow models in order to predict bottomhole circulation pressure when performing UBD/MPD operations. A new model is developed that utilizes the latest mechanistic multiphase flow models; the developed model calculates the bottomhole circulation pressure as a function of surface injection rates, choke pressure and time.
The developed model can be used in designing and optimizing UBD/MPD operations in terms of determining the correct injection rate and/or choke pressure. In addition, the developed model is used to utilize the reservoir energy to attain correct bottomhole conditions. The developed model in addition to utilizing the latest mechanistic models also reduce the error in calculating the bottom hole pressure by incorporating an algorithm in which the injection rates are calculated in-situ rather than assuming constant injection rates.
The model is validated against data from literature and against a commercial simulator. Results show that the developed algorithm has increased the accuracy in predicting bottomhole pressure by incorporating the changes in new gas and liquid injection rates.
In April 2010 we were reminded that Drilling operations are amongst the most hazardous in the world, having the potential for Major Incidents, with the Deepwater Horizon rig fire and explosion. This incident resulted in 11 lives being lost, almost 5,000,000 million barrels of oil being spilt into the Gulf of Mexico over an 87 day period and significant financial loss for bp. This Major Incident also served to remind us that while traditional "Personal Safety?? programs are important to achieve safe drilling operations, these alone cannot effectively manage Major Incident Hazards. E&P Operations can learn valuable lessons from the Process Industry in this regard.
This paper looks at how "Process Safety Management?? implementation, aimed at reducing the potential for Major Incidents, has commenced at an onshore E&P operation. It also discusses the challenges of integrating the culture of Process Safety into existing company culture for operations involving over 60 land rigs comprising both local and international Drilling Contractors and Service Companies.
Process Safety Management system is used to describe those parts of an organisation's management system intended to prevent major incidents arising out of the production, storage and handling of dangerous substances (UK HSE, 2012). It addresses the potential release of these substances caused by:
• Mechanical Failures
• Process Upsets
• Procedures/Human Error
Kuwait Oil Company (KOC) is a subsidiary of Kuwait Petroleum Corporation (KPC), and is involved in the exploration and production of hydrocarbons on land in the state of Kuwait. Existing production is approximately 2.9 mmbopd, with future production targeted at 3.65mmbopd by 2020.
The Exploration and Production (E&PD) Directorate is involved in identifying reserves, drilling new wells and servicing existing wells. It consists of 8 Groups as shown below, and is headed by a Deputy Managing Director (DMD). As most of the PSM challenges in E&PD Directorate lie with Drilling and Service Company operations, the primary focus of this paper will be in these areas.
Mendoza, Alberto X. (ExxonMobil Neftegas) | Gaillot, Philippe (ExxonMobil Exploration Company) | Yin, Hezhu (ExxonMobil Abu Dhabi Offshore Petroleum Company) | Nicosia, Wayne (ExxonMobil Upstream Research Company) | Guo, Pingjun (Exxon Mobil Corporation) | Mardon, Duncan (ExxonMobil Upstream Research Company) | Passey, Quinn R. (ExxonMobil Upstream Research Co.) | Wertanen, Scott R. (ExxonMobil Exploration & Production Surumana) | Zhou, JinJuan (ExxonMobil Upstream Research Company) | Fitz, Dale Edward (ExxonMobil Upstream Research Co.)
Over last several years, the ability to perform accurate, quantitative formation evaluation in high-angle and horizontal (HA/HZ) wells has been increasingly recognized as a high priority, unsatisfied need within the formation evaluation (FE) community. The industry has realized that the ability to drill extended reach wells has surpassed the ability to evaluate them. Well logs are often underutilized for geologic modeling and assessment applications due to lack of confidence in petrophysical analysis results.
In this paper, we introduce a state-of-art formation evaluation toolkit specifically developed for quantitative interpretation of high angle and horizontal well logs. Starting with wellbore images and standard triple-combo field logs, the workflow consists of: 1) three-dimensional (3D) and two-dimensional (2D) display modules for well path, wellbore images logs, scalar logs and dips to quality control (QC) the data; 2) a comprehensive image analysis module combined with log analysis to build a 3D geometrical earth model; 3) a depth coherence processing (DCP) module to effectively correct recorded borehole images of different logging tool sensors with different depths of investigation (DOI) back to borehole size (BS); 4) a 3D joint inversion module to accurately model and interpret gamma ray (GR), neutron, density, and resistivity logs, to build a common petrophysical earth model; and 5) an output module in which the common earth model is populated with bedding geometries and petrophysical property distributions.
The advanced formation evaluation toolkit described in this paper enables geoscientists to realize much more value than ever before from high-angle and horizontal well data, especially in thinly bedded reservoirs. The detailed description of the internal architecture and lateral petrophysical characterization of the reservoirs are essential for understanding stratigraphy and conditioning geological models. The improved estimations of the petrophysical properties yield more accurate estimates of reserves in place.
In order to develop the design requirement with current regulatory and contemporary HSE practices, for a typical sour oil/gas production facility, a hypothetical case of about 3 mol % v/v H2S in gas and 300 ppm w/w H2S in oil, of multiphase feed stream, has been studied through the dispersion modeling for the conceptual stage. The findings indicated credible downwind lethal / semi lethal threat distance up to 300 meters. The conclusions of the H2S toxic risk assessment combined with the inherent safe design guidelines have yielded an entirely new set of requirement for the risk reduction. To start with it was realized that safe distance control room should be constructed and facilities should be designed for the remote operation, utilizing the new trends of foundation field bus, electronic marshaling and SIL-3 fiber optic sensors. The facility should be access controlled with mandatory PPE requirement of personal H2S monitors and personal quick donning (5 sec) escape SCABA (15 minutes capacity). The centrifugal compressors should be new generation design of enclosed and hermetically sealed type, levitated with magnetic bearing, without dry gas seals and oil lubrication. The vessels should be ASME Section VIII "lethal service?? design and plant piping should be as per fluid category "M?? of ASME B31.3 chapter VIII. Furthermore, stress relieving for thicknesses as low as 10 mm, rather than ASME B31.3 code specified >19 mm would be required. Small valves <4?? sizes should be of forged steel instead of cast steel. The export oil/gas pipelines and flow lines should be designed for =< 50~60 % of SMYS. Plate instead of Shell and Tube Exchangers. Adequate margins between vessels design and operating pressures to avoid PSV chattering. The PSV's to have acoustic monitoring. The facilities should be designed free of valve pits and internal corrosion monitoring pits.
Al-Kandary, Ahmad (Kuwait Oil Company) | Al-Fares, Abdulaziz (Kuwait Oil Company) | Mulyono, Rinaldi (Kuwait Oil Company) | Ammar, Nada Mohammed (Kuwait Oil Company) | Al naeimi, Reem (Baker Hughes) | Hussain, Riyasat (Kuwait Oil Company) | Perumalla, Satya (Baker Hughes)
Role of geomechanics is becoming increasingly important with maturing of conventional reservoirs due to its implications in drilling, completion and production issues. Exploration and development of unconventional reservoirs involve maximizing the reservoir contact and hydraulic fracturing both of which are heavily dependent on geomechanical architecture of the reservoirs and thus require application of geomechanical concepts from the very beginning.
To support the unconventional exploration and conventional reservoir development in Kuwait, country-wide in-situ stress mapping exercise has been carried out in nine fields of Northern Kuwait. Stringent customized quality control measures were put in place to evaluate stress orientation. Cretaceous and sub-Gotnia Salt Jurassic rocks exhibit distinct patterns of stress orientations and magnitudes. While the variations in stress orientation in the Cretaceous rocks are within a small range (N40°E-N50°E) and consistent across major fault systems, the Jurassic formations exhibit high variability (N20°E-N90°E) with anomalous patterns across faults as well as in the vicinity of fracture corridors. Moreover, the overall stress magnitudes were found to be much higher in the strong Jurassic section compared with the relatively less strong Cretaceous strata. During the analysis, it was also observed that several natural fractures in Jurassic reservoirs appear to be critically stressed with evidences of rotation of breakouts.
Using geomechanical models from a specific field, the effects of in-situ stress, pore pressure and rock properties on formations were evaluated in inducing wellbore instability during drilling operations in a tight gas reservoir. It was found that the most favorable orientation for directional drilling is parallel to the maximum horizontal stress (SHmax) within that field.
The geomechanical study provided inputs not only for wellbore stability during drilling, but also regarding the response of natural fractures to in-situ stresses to become hydraulically conductive (permeable) to act as flow conduits. The fracture model of the field shows that the dominant fracture corridor trend in the field is NNE coinciding with present day in-situ maximum principal stress direction.