SCAL measurements on core material from the Dunga Field in Kazakhstan clearly show two distributions of flow regimes, one with flow (good flow sand) and one without. If no precautions are taken the SOR and SWIR measurements are not representative of the reservoir. It is essential to map out the location and the nature of the high and low permeable zones in order to properly model the reservoir flow pattern. Visual inspection of the core reveals mm-scale bedding of darker and lighter facies. This paper describes an imaging study to address whether the bedding and the flow/saturation properties could be related and an attempt to quantify the good flow regime.
Scanning electron microscopy (SEM) images taken at a magnification of 10000 times and stitched together to show the area across the bedding apparent in core do not reveal anything other than homogeneously distributed grains, feldspar and clays. This result indicates that either the flow heterogeneities are not related to the laminations, or that the grain size does not play a role.
Computational tomography (CT) scanning was used in order to determine the density and spatial differences in the rock. The 3D tomograms were recorded in-house at an approximately 3 µm resolution and supplemented by experiments conducted at the European Synchrotron Radiation Facility (ESRF) where a resolution of 700 nm was achievable. Both of these tomograms clearly show structured, denser regions, which would likely be responsible for the observed flow heterogeneities. The CT results were combined with an automated mineralogy approach to determine the composition of the cores across the laminations. The primary focus of this experiment was to investigate whether the denser bands are related to certain mineralogy in the core sample. The QEMScan results do indicate that the dense bands are a result of clay rich sand laminations. This seems to constitute the regime of the porous media where the pore space cannot be resolved (the microporous regime).
The segmentation of the 3D data and following pore-connectivity analysis is used in an attempt to quantify the amount of good flow sand. The 3D data does not give rise to a successful prediction of the permeability which is indicating that even the good flow sand has permeability in the single-digit mD range. This is the case for both the 700 nm and 3 µm resolution datasets. There is a linear correlation between the connected porosity versus both the experimental results for SOR and SWIR. Thus, it may be possible to predict SOR and SWIR from CT measurements on plugs where SCAL measurements have not been conducted. It is, however, noted that the quantification of good flow sand (via the connected porosity) from the images does agree very well with our description of SWIR based on the good flow sand/poor flow sand combination. This is ascribed to the different length scales involved in the measurements and that fact that the limit is 3 µm for the images that we can readily treat. Getting the scales right will be a venue of future investigation.
Karst carbonate reservoir is playing more and more important role in current petroleum industry, and it is the same in study Tazhong area of middle Tarim basin and even the whole basin. Meanwhile, it is noted that paleogeomorphology of carbonate karst unconformity has obvious control on reservoir development and even hydrocarbon accumulation based on many case studies. Therefore, paleogeomorphology reconstruction is often very fundamental but indispensable study for exploration and production activities in such kind of reservoirs.
The study carbonate unconformity, i.e. the top of Yingshan formation of early Ordovician, typically occurs at burial depth of 5.2~6.5 km, which is almost the same as that of northern Tarim basin, such as Lungu area. However, there are more challenges here in the work of paleogeomorphology reconstruction for Tazhong area when compared to that for northern Tarim basin: 1) the study carbonate unconformity has much lower relief contrast on paleogeomorphologic micro-unit scale, 2) the overlying formation of Lianglitage is carbonate-dominated and contains many reef-shoal intervals (especially for the upper Lianglitage formation), and 3) the current structure of unconformity horizon seems much different from paleogeomorphology surface. These cause that the often-used methods fail, for example, the paleogeomorphology derived from the whole thickness of overlying Lianglitage formation will be distorted because of higher carbonate production rate at some topographic highs, which is different from a normal clastics case where thicker usually means lower and thinner means higher, like the situation in northern Tarim basin.
Since the start of production, the Al Khalij field, Qatar, has experienced a relatively rapid increase in water cut evolution and decrease in reservoir pressure. The associated consequences bring new challenges to the ESP development concept, increasing ESP exposure to free gas and power requirements. Therefore, operating and maximizing production of Al Khalij field requires not only integrated thermo-hydraulic fluid modeling from reservoir to surface, but also ESP gas handling and power supply managements. Integrated modeling is a cross-functioning simulation, monitoring and decision tool capturing the interactions from reservoir to surface facilities and from today to the end of field life. This paper describes the associated benefits of an innovative Al Khalij field Integrated Asset Model embedded into live data environment and performing production optimization accounting for ESP gas handling (gas volume factor and minimum bottom-hole pressure) and power supply management constraints (ESP motor, variable speed drive and wells and platforms transformers). As for any Integrated Asset Model, the reservoir, the wells, and the network thermo-hydraulic behaviors have been calibrated on the production data. The reliability of the well models to reproduce the measured production data has been demonstrated and is described in this paper. It has even proven capability to detect abnormal hydraulic and electrical behavior of the ESP motor and/or the pump. In the Integrated Asset Model, the intensity and voltage values are calculated at the ESP motor, the variable speed drive and the wells and platforms transformers levels. The electrical load based on these equipments design is used through an innovative workflow to constraint the field production optimization together with the free gas management constraints. The Integrated Asset Model has then been embedded into a live data environment of the field (DOF) for monitoring and automated models management and is used to further optimize the production including ESP free gas and power supply managements, and to anticipate on future debottlenecks.
Hydrocarbon gas injection is the most widely applied process after waterflooding, and is a promising enhanced oil recovery (EOR) injectant for use in Middle East carbonate oil fields. Gas injection improves microscopic displacement efficiency and generally acts as pressure maintenance; however, unfavorable mobility ratio can negatively impact the ultimate recovery due to viscous fingering and gravity override.
This paper describes two gas injection pilots that have been implemented in offshore Middle-East carbonate reservoirs, a secondary and a tertiary gas injection through line drive to assess injectivity, productivity, macroscopic sweep efficiency, flow assurance and operational efficiency in a field that has long water-injection history. A strong monitoring plan, including an observer well, was applied through time-lapse saturation logging, pressure measurements, production testing, tracer campaign, etc. to evaluate the pilot efficiency and address key uncertainties upfront prior to full-field application.
This paper describes the pilot performance in the context of full-field development, local and macroscopic displacement efficiency, flow assurance issues, and operational learnings. The gas injection performance is strongly impacted by reservoir heterogeneity, gravity segregation and the existing pressure gradient, and the history match performed indicates near-miscible or miscible behavior depending upon local pressure regimes, which thus govern the ultimate recovery. The history match also shows that for the same pilot, performance can be further improved through water-alternating-gas (WAG) injection, resulting in a viable development scheme for full-field implementation.
Xiong, Y. (ExxonMobil Upstream Research Company) | Li, C. (ExxonMobil Upstream Research Company) | Desai, S. (ExxonMobil Upstream Research Company) | Pacheco, J. (ExxonMobil Upstream Research Company) | Ciecko, E. (Mobil Producing Nigeria Unlimited) | Orhue, D. (Mobil Producing Nigeria Unlimited) | Mboho, E. U. (Mobil Producing Nigeria Unlimited) | Monahan, C. (ExxonMobil Production Company)
An important element that is often overlooked during chemical qualification and application is the compatibility between oilfield chemicals (OFCs), which can critically impact the ability of the chemicals to meet their desired function in the field. In the area of corrosion control, one important example of this is the interference of oilfield chemicals on corrosion inhibitor effectiveness. In this study, we aimed to identify the primary sources of inhibition failure during the simultaneous use of a corrosion inhibitor with scale inhibitor, drag reducing agent, and biocides under particular field conditions. Results show that one type of biocide completely rendered the corrosion inhibitor ineffective, while other OFCs had no significant impact on corrosion inhibition. The findings in this study highlight the necessity for chemical compatilibty checks during corrosion inhibitor qualification, or when there is a change in other OFC formulation/application, to ensure proper corrosion protection is maintained. Additional work is ongoing to improve the fundamental understanding of chemical compatibility.
A recently developed 2 ?-in. intelligent coiled tubing (ICT) system combines real-time downhole data monitoring with the capability to simultaneously provide downhole power, significantly improving operational efficiency and accelerating well recovery in all types of CT operations. From milling, stimulation, and well cleanouts to gas lifting, camera services, logging and perforating operations, this novel system can provide accurate, real-time downhole monitoring of high-resolution depth correlation, differential pressure, and temperature data.
The real-time ICT system consists of a non-intrusive electrical conductor wire, surface hardware and software, and a versatile 2 ?-in. bottomhole assembly (BHA) that incorporates the conductor release assembly, casing collar locator (CCL), pressure, and temperature sensor package, and BHA release function. Switching between different applications is as simple as changing out the BHA, which reduces the need to rig-up and rig-down and leads to operational time and cost savings. The main advantage of this system is that it eliminates the downhole uncertainties. For instance, using the real-time downhole depth, pressure, and temperature data, the CT field crew can react to changing conditions, make decisions based on dynamic downhole events, and eliminate missed or wasted runs.
Several case studies have been recently presented in an accompanying paper (SPE-174850). They involved an ICT conveyed camera operation in North America; a complex cement milling, cleanout, and perforating operation in Netherlands; an inflatable plugs setting operation in Brazil; a complex drifting, logging, jetting, zonal isolation, and scale removal operation in Brazil; and a matrix acidizing operation in Brazil. In this paper, several other representative cases are presented. First, an ICT system was used in a newly drilled well in Middle East to cut a stuck drill pipe. Second, an operation for creating a thief zone and matrix acidizing was performed in a deepwater well in Brazil. Third, a complex cleanout, milling, selective perforating, and acid stimulating operation was performed in a horizontal producer in North Sea.
The paper reviews the real-time ICT system and discusses the data acquired during these field operations. The system performance and benefits confirmed during the three operations are presented. These findings outline the versatility of the 2 ?-in. ICT system, the predictability of successful operations resulting from using this system, and the cost and time savings for operators.
Fluctuations in commodity pricing and supply and demand are inherent to the upstream oil and gas market. In recent years, other emerging factors, often onset by these fluctuations, have begun to contribute to the complexity within the human capital component of the industry. Business and human resource leaders are forced to make increasingly difficult decisions regarding personnel capabilities, utilization, and reduction in attempt to align the enterprise in a briskly changing landscape.
With the current knowledge gap between entry to mid-career level and seasoned personnel, coupled with the volatility in commodity prices and organizations' need to react, learning and human resource professionals must navigate a dynamic challenge with personnel: engage high potential, talented employees and ensure their retention in order to create personal career satisfaction, thus securing a sustainable knowledge transfer to developing professionals. This challenge amplifies the need for a diagnostic approach to workforce planning and management in upstream oil and gas organizations.
Traditional talent management tools, such as learning programs, competency initiatives, and career paths, offer proven methods for the employee and organization to maneuver industry cycles. However, as the cycle shifts under the pressure of new challenges, the static and rigid nature of traditional approaches must be examined and refined in order to provide a sustainable talent pipeline. This paper will examine a case study of a highly visible and well-defined talent management framework that provides management with a strategic and calculated method for assessing employee capability against market compatibility in order to make sound decisions in a time of restructuring. Additional research will demonstrate the positive impact of implementing a competency-based, career progression structure to meet business needs, motivate employees, and ensure knowledge retention within an organization.
Finally, it will introduce a brief overview of leveraging action-learning events to incite employees and optimize training resources, such as: intentional mentoring, on-demand learning, and core competency assessment. The paper will establish the value of combining these efforts with career development into a cohesive framework that creates a sustainable, transparent roadmap to shape and facilitate highly engaged, visible, and proficient professionals with the flexibility and agility to withstand future cycles.
As wells increase in complexity, new challenges must be addressed in order to produce hydrocarbons in the best way possible. Some wells should be cemented in two stages because of the risks of fracturing the lower zone. Running a long casing string increases the equivalent circulating density (ECD) and also increases the chance of damaging that zone, so running a liner is the best option.
Cementing liners in two stages has been performed with conventional liner hangers for some time because of their capability to run an inner string and their capacity for manipulation after the hanger is set. Now, new technologies allow those treatments to be completed with expandable liner hangers (ELH).
The ELH provides a premium liner top seal (Williford, Smith, 2007) and excellent tensile capabilities. They also help to improve the cement bond by allowing the movement of the string while the cement is being pumped in place. ELHs have proven to be a reliable tool (
This paper discusses the first true two-stage cement job with an ELH performed in Kazakhstan. The use of the ELH helped the operator reach total depth (TD), cement the two zones without issues, and create a premium barrier at the top of the liner.
In a GTL plant located in Qatar, produced water (PW) is considered for treatment and reuse in the existing onsite Effluent Treatment Plant (ETP).
The onsite ETP deploys both conventional and advanced water treatment technologies including flocculation flotation unit, biotreatment, membrane filtration (submerged Ultrafiltration (sUF) and Reverse Osmosis (RO) units), evaporation and crystallization processes, to produce water for reuse within the plant mainly for cooling and power generation among many other uses.
Current PW disposal is in deep wells. PW reuse was considered an economically viable option for the plant due to its quality (TDS < 4000 mg/L).
A test work was conducted to determine the feasibility to route the PW to existing onsite ETP. Firstly, the PW was chemically analysed for key contaminants including hydrocarbons (condensate), heavy metals and naturally occurring elements, Total Dissolved Solids (TDS) etc.
Hydrate inhibitor is normally dosed to the PW during the winter season while Corrosion Inhibitor (CI) is dosed continuously throughout the year. This results in two distinct streams, i.e. a "Winter PW stream" (Stream A) and a "Summer PW stream" (Stream B).
The potential impact of Stream A and Stream B must be evaluated before routing to onsite ETP is considered feasible.
Based on sample analysis (pH, conductivity, COD, TOC, ion chromatography, metals scan, toxicity tests and 28 days COD die-away test), it is known that both Streams A and B have the potential to adversely affect the daily performance of the onsite biotreater, with additional risk of sUF/RO membrane fouling (scaling).
The following have been considered in the study:
Hydraulic load of PW to the onsite ETP Quality of Streams A and B, in terms of Chemical Oxygen Demand TDS which is <4000 mg/L (0.4% wt) Presence of scaling components (Ca, Mg and Ba) Heavy metals in PW
Hydraulic load of PW to the onsite ETP
Quality of Streams A and B, in terms of
Chemical Oxygen Demand
TDS which is <4000 mg/L (0.4% wt)
Presence of scaling components (Ca, Mg and Ba)
Heavy metals in PW
Stream A is considered first for pre-treatment in an onsite Wet Air Oxidation (WAO) unit to destroy hydrate inhibitor, while Stream B will be stored temporarily in a holding tank to ensure complete condensate separation, prior to routing of both pre-treated effluent to the onsite ETP.
Experimental test work conducted over a period of 9 months using two bench bioreactors operated at similar hydraulic and solids residence times as the onsite ETP showed COD levels are reduced to levels that meet the specification for further polishing in downstream UF and RO units. Test work suggests PW (Streams A and B) to be compatible with onsite ETP.
Sheikhan, Jassim Mohammed (Qatargas Operating Company) | Zainab, Ishak (Qatargas Operating Company) | Janson, Arnold (ConocoPhillips Global Water Sustainability Center) | Adham, Samer (ConocoPhillips Global Water Sustainability Center)
Qatargas continually strives to adopt best industry practices throughout its gas extraction and production operations. The Jetty Boil-off Gas Project, the Greenhouse Gas Management Strategy and the Wastewater Management Strategy are prime examples. These projects, and various other initiatives, demonstrate Qatargas' commitment to promote energy security, water sustainability and protection of environment, all important outcomes of the Qatar National Vision 2030.
Key elements of the Wastewater Management Strategy are two advanced Wastewater Recycle and Reduction plants (WRRs) currently being built to treat process waters from three liquefied natural gas (LNG) production plants. Each of the WRRs is designed to treat 5 separate process waste streams with a combined average design flow 176 m3/h and 60% recovery as boiler feedwater targeted. The unit processes include both conventional technologies, e.g. de-oilers, sand filters, walnut shell filters, and advanced technologies, e.g. membrane bioreactors and reverse osmosis. This paper includes an overview of the WRR systems, summarizes unit process designs and, based on a comprehensive mass balance, highlights the significance of membrane rejection and operating temperature on the final effluent quality. Also, in preparing the design basis, certain design assumptions were made and this paper includes the results of a sensitivity analysis conducted to determine the impact different design assumptions have on effluent quality.
This paper identifies the challenges in designing a state-of-the-art WWTP with varying quality feed streams and with different end-uses for the treated water. This will be educational for engineers and professionals in the oil & gas industry interested in developing more sustainable methods of handling process wastewaters generated during oil & gas processing operations.