Tonner, David (Diversified Well Logging) | Swanson, Aaron (Diversified Well Logging) | Hollingshead, Ron (Diversified Well Logging) | Hughes, Simon (Diversified Well Logging) | Seacrest, Stephen (PetroLegacy Energy) | McDaniel, Bret (PetroLegacy Energy) | Leeper, Jay (Solid Automation)
From the very early days of oil and gas exploration, appraisal and development drilling, samples have been collected at the rig by mud logging personnel to conduct a preliminary geological analysis of the rock being drilled. This collection typically involves a sample collection recipient, board or bucket to collect a sample of rock over the desired interval. The sample is then sieved and cleaned in the appropriate way depending on the type of drilling fluid being used. As penetration rates have increased in some instances to more than 400 ft. / hr. the sample resolution has deteriorated exponentially. From an ergonomics perspective, the highest frequency to which a person onsite can collect a sample is once every 20 minutes. At 300 ft. / hr. this translates to 100 ft. of drilled rock. A new device has been developed and deployed which automates this manual process and thus ensures faster and more accurate collection of geological samples of the drilled rock interval. Sample resolutions of 5ft rock intervals have been attained at 400 ft./ hr. This technology has provided an important technological breakthrough and enables reduction of personnel at the rig site with a subsequent reduction in cost and HSE risk, particularly in areas of H2S. It further has provided for the potential integration with Measurement while drilling personnel. For both conventional and unconventional play development, this has provided oil and gas operators with an important and cost and risk reducing modus operandi compared to conventional drilling and evaluation techniques. The tool was deployed for an operator in West Texas where both manually collected traditional mudlog samples and automatically collected samples were taken. The samples were analyzed and compared for rock content. In addition, comparisons were made between point sampling with the automated system versus samples collected over a defined interval manually. Results of these comparisons will be presented.
A new method of automated drill cuttings sample collection has been successfully deployed. The new method provides a step change improvement in accuracy and resolution for sampling the rock record during drilling.
Additional data of the rock record provides potential insights to optimize wellbore placement and provide increased geo-mechanical data to optimize completions.
Dasgupta, Suvodip (Schlumberger) | Raina, Ishan (Schlumberger) | Povstyanova, Magdalena (ADNOC E&P) | Laer, Pierre Van (ADNOC E&P) | Baig, Muhammad Zeeshan (ADNOC E&P) | Casson, Neil (ADNOC E&P) | Marzooqi, Hassan Al (ADNOC E&P) | Suwaidi, Salama Jumaa Al (ADNOC E&P) | Ali, Humair (Schlumberger) | Subbiah, Surej Kumar (Schlumberger) | Mello, Ashish D' (Schlumberger)
Al-Shamali, Adnan (Kuwait Oil Company) | Mishra, P. K. (Kuwait Oil Company) | Verma, Naveen K. (Kuwait Oil Company) | Quttainah, Riyad (Kuwait Oil Company) | Al Jallad, Osama (Ingrain Inc.) | Grader, Avrami (Ingrain Inc.) | Walls, Joel (Ingrain Inc.) | Koronfol, Safouh (Ingrain Inc.) | Morcote, Anyela (Halliburton)
In Kuwait, the Najmah source rock is characterized by a complex diagenetic history and depositional variability. Accurate determination of the porosity and permeability logs is essential for improved petrophysical evaluation, which may not be properly performed using conventional methods. This complexity makes the conventional evaluation methods alone insufficient to determine porosity and permeability logs accurately. A major goal of this study was to produce high-resolution porosity-permeability logs for Najmah Formation using advanced digital analysis and geochemistry measurements.
Sixty (60) feet of continuous core were analyzed from an oil field in southwest Kuwait. The analysis started with dual-energy x-ray CT scanning of full-diameter whole core and core gamma logging. Plug-size samples were selected to represent the varying porosity and organic matter content along the entire core length. Two-dimensional Scanning Electron Microscopy (2D SEM) and three-dimensional Focused Ion Beam (3D FIB-SEM) images were acquired and analyzed to accurately determine the organic matter content and porosity. Matrix permeability was directly computed from the 3D FIB-SEM images using the Lattice Boltzmann method. The SEM porosity was calibrated by determining the amount of movable hydrocarbons at in-situ reservoir conditions based on geochemical analyses (XRF, XRD and LECO), pyrolysis indices, PVT data and adsorption isotherm experiments.
The digitally obtained porosity and permeability data showed a unique trend that was used to produce permeability at the core level. The integration between digital analysis and geochemistry data increased the estimated porosity and confirmed higher mobile hydrocarbon in the reservoir in comparison with the measured data at the surface. This produced a new porosity-permeability trend that was more representative of the reservoir conditions and caused a significant increase in the rock permeability.
The integration between the digital SEM analysis and the geochemical measurements was critical to estimate in-situ porosity and permeability characteristics of the tight formation under study. Moreover, this analysis provided an important tool for obtaining different high-resolution porosity and permeability logs based on various porosity considerations (effective, organic, inorganic, clay). This would lead to higher accuracy in determining reservoir properties for improved quantification of reserves and productivity.
Oil fingerprinting is a common name for techniques based on geochemical analysis of hydrocarbon fluids composition which could provide valuable and unique information for well and reservoir management. Hydrocarbons in oil and gas deposits are affected by different processes, such as: biodegradation, gas flushing, water washing and evaporation. The degree of change depends on many factors: temperature, reservoir compartmentalization, tectonics, aquifer activity etc. Consequently, hydrocarbons initially migrated from one source rock become different in different reservoirs and compartments. Evaluation of changes in composition allows identification of hydrocarbons from different reservoirs, in other words to identify unique "fingerprints" of hydrocarbons. This information can be very valuable for production allocation between reservoirs and for needs of well and reservoir management. This article summarizes the results of a pilot oil fingerprinting project on Astokh oil field based on High Resolution Gas Chromatography (HRGC). The primary objective of this work was to develop a methodology for production allocation in comingled oil producers based on HRGC as applied for the Astokh area. In the course of work some more opportunities were identified, for instance monitoring of reservoir dynamics which could turn out to be more powerful than the primary objective.
Siddiqui, M. A. (KOC) | Al-Mutairi, Moute'a (KOC) | Mankala, R. (KOC) | Qayyum, S. (Resman) | Prusakov, A. (Resman) | Leung, E. (Resman) | Alabdulwahab, M. (KOC) | Al-Rashidi, M. M (KOC) | Al-Ali, A. (MEOFS)
Kuwait Oil Company is pursuing fast track technology deployment in its fields to meet the strategic target of production. The horizontal wells provide good mean to exploit the reservoir through increased reservoir contact but it brings some inherent problems in optimizing production and low cost well intervention. To address these inherent challenges, the deployment of inflow control device (ICD) has become a normal trend of completion in horizontal wells.
The completion of horizontal wells with ICDs helps in optimizing production but information of inflow contribution from each section qualitatively and quantitatively is still a challenge. In this perspective, KOC has deployed intelligent chemical inflow tracer technology combined with On/Off ICDs below an ESP in a horizontal well located in its northern field to assess the inflow performance of the production. The horizontal well was drilled through a heterogeneous reservoir, which was compartmentalized with swell packers and completed with On/Off ICDs. In these types of wells, traditional production logs are considered risky and expensive due to the limitations of using a small-diameter coil tubing, which must fit through the Y-tool on the ESP. This small diameter coil tubing will go into helical buckling before reaching the toe of the well resulting in an incomplete log for the well. In some cases, the wells are lacking Y-Tool facility, which practically does not allow production logging in the well.
In such cases, the intelligent chemical inflow tracers are used to provide a qualitative assessment of the clean-up phase of production, quantitative inflow information from each zone, and to identify the section producing water along the horizontal well. The use of intelligent tracers overcame the intervention challenges by installing intelligent downhole chemical sensors in pup-joint carriers next to the ICD joints in each compartment from heel to toe to meet monitoring objectives of Kuwait Oil Company. Fluid samples collected from the surface flow lines were analyzed for unique chemical tracer signatures and interpreted the corresponding tracer signals. This has resulted into identification of quality of fluid flowing from each section concomitant with its quantification. In addition, the pilot results have increased the reservoir understanding that leads to optimum ICD designs for future wells in the same reservoir.
This paper discusses the first well installation of its kind in Kuwait, the methodology for selecting the technology, the deployment in the well, and the interpretation of results of water and oil tracers obtained during different monitoring campaigns through fluid sampling.
AbstractAppropriate design and operations of deepwater facilities require prior knowledge of expected properties of gas, oil and water to be produced. With the subsurface uncertainty of reservoir connectivity, compositional gradients, aquifer presence and support and the extent of the reservoir to be developed, it is challenging to put bounds to the expected fluid properties. Any estimates of production rates and the fluid property variations in a field to be developed is riddled with uncertainty, as are other aspects of the development. The integrated project team consisting of reservoir, flow assurance, facilities and production disciplines is tasked to convert this uncertainty to a robust set of design basis for execution. For the team to be successful in this endeavor, the team members are expected to be aware of the potential impact of the production chemistry on the project success. This paper is a discussion of principal fluid characteristics that may compete with other uncertainties to define project risks. In this discussion, production chemistry refers to both fluid compositions and the macroscopic flow-related elements. For example, fluid compositions and flowing pressure and temperatures impact hydrate, paraffin and/or asphaltene precipitation and deposition characteristics. And kinematic properties such as viscosity and phase equilibria impact the design of flowlines, separators and ultimately operations. Specific discussions are on condensate and water properties in wet gas field developments and for oil developments, asphaltene and water properties are discussed. Intent of this discussion is to assess the influence of fluid properties on successfully developing and operating wet gas and black oil fields.
McCaffrey, Mark A. (Weatherford Laboratories) | Al-Khamiss, Awatif (Kuwait Oil Company) | Jensen, Marc D. (ConocoPhillips Alaska) | Baskin, David K. (Weatherford Laboratories) | Laughrey, Christopher D. (Weatherford Laboratories) | Rodgers, Wade M. (Occidental Petroleum)
AbstractUsing examples from the Permian Basin of Texas, the North Slope of Alaska, and the Bergan Field of Kuwait, this paper describes how oil geochemical fingerprinting can be applied to diagnose quickly and easily three production problems that may affect highly deviated wells.High-Resolution Gas Chromatography can be used to quantify ~1,000 different compounds in an oil, and the relative abundances of those compounds form a geochemical fingerprint. Geochemical differences between fluids in adjacent reservoirs can serve as natural tracers for fluid origin, allowing changes in production in highly deviated wells to be understood.Application 1: In wells that are fracture stimulated, oil fingerprinting can be used to assess whether induced fractures have propagated out of the target interval and into overlying or underlying formations. Oil fingerprinting can be used to quantify what percentage of the produced oil and gas is coming from each interval and how the effective stimulated rock volume changes through time. This concept is illustrated here with a Permian Basin example.Application 2: In wells with multiple laterals in the same well (such as those in certain North Slope, Alaska fields), sand can settle out of the production stream and form sand bridges that obstruct production from one or more of the laterals. In addition, sand co-produced with oil from shallower laterals can settle at the bottom of the vertical section during regular production and obstruct the entry to a deeper lateral. Geochemical fingerprinting can be used to determine quantitatively the contribution of each of several zones to a commingled oil stream. This technique allows the operator to identify sanded-out intervals for fill cleanout (FCO).Application 3: If two reservoirs are both oil bearing, but are of very different permeability, horizontal wells with an intended landing target in the tighter reservoir may be adversely affected if the well path contacts the more permeable reservoir. The Mauddud reservoir in Kuwait provides examples of this phenomenon. The Mauddud carbonate occurs between two massive clastic reservoirs, the Wara and the Burgan. Average Mauddud porosity is 18% with low permeability (1-10 mD), characteristics which make this reservoir a candidate for horizontal drilling. However, some lateral wells in this carbonate may encounter the adjacent, more permeable reservoirs over a short portion of the well path. In such cases, production from the adjacent reservoir may account for virtually all of the well's production, even though the well was intended to be completed solely in the tighter reservoir. Oil fingerprinting can be used to identify wells affected by this problem.A common theme unifies these three applications: Geochemical differences between in-situ fluids in adjacent reservoirs can serve as natural tracers for fluid movement. However, these techniques have been under-applied as tools for optimization of production from highly deviated wells. This paper illustrates the application of this technology to that well type in a variety of play types.
Two different sources of H2S have been identified in the ultra-sour gases in the Arab Formation in Abu Dhabi, based on sulfur isotope measurements of both anhydrites and H2S. In the Upper Arab reservoirs, H2S appears to be generated
Steiner, S. (ADCO) | Raina, I. (Schlumberger) | Dasgupta, S. (Schlumberger) | Lewis, R. (Schlumberger) | Monson, E. R. (ADCO) | Abu-Snaineh, B. A. (ADCO) | Alharthi, A. (ADCO) | Lis, G. P. (Schlumberger) | Chertova, A. (Schlumberger)
ADCO started its unconventional exploration campaign in 2012 targeting the tight carbonate sequences known as Wasia Group, onshore Abu Dhabi. A front-end loaded data gathering strategy was employed to acquire extensive latest generation logging data tailored for unconventional reservoirs. In a number of wells the entire reservoir section was cored, often up to 800 ft per well, leading to more than 3000 ft of core retrieved to date. ADCO applied unconventional core analysis technologies, such as retort analysis, to generate the optimal core results. Key parameters such as effective porosity, pore size distribution, TOC, source rock maturity, mineral compositions and fluid saturations were determined from logs and core data (where available).
This paper will focus on the petrophysical challenges during the evaluation of the Wasia Group. We will demonstrate that conventional core analysis techniques have only limited applicability, whereas core analysis techniques designed specifically for unconventionals provide more relevant results. A log analysis methodology centered on the application and importance of NMR in unconventional liquid plays is presented. Porosity data measured through retort analysis provide an excellent fit to NMR log-based porosity measurements. Conventional core analysis results generated a poor fit to log porosity, and the resulting values exhibited scatter with a large standard deviation.
Log data-derived rock typing was performed. It is based on principal component analysis of the reservoir section. Rock classification may help in selecting suitable zones for hydraulic fracture initiation.
Lessons learned from the initial wells for core recovery and analysis techniques are summarized below and have been implemented in later wells: Preserve part of the core for robust saturation measurements. Stop acquisition of conventional poro-perm data Focus on unconventional-specific retort-based techniques for core petrophysics Focus on pulse decay permeabilities Use scratch test to aid in core analysis sample selection process, especially for rock mechanics Add core
Preserve part of the core for robust saturation measurements.
Stop acquisition of conventional poro-perm data
Focus on unconventional-specific retort-based techniques for core petrophysics
Focus on pulse decay permeabilities
Use scratch test to aid in core analysis sample selection process, especially for rock mechanics
The complete integration of core and log data has allowed for a thorough assessment of the unconventional hydrocarbon potential within the ADCO concession.
Golab, A. (FEI Digital Rock Services) | Deakin, L. (FEI Digital Rock Services) | Ravlo, V. (FEI Digital Rock Services) | Mattisson, C. (FEI Digital Rock Services) | Carnerup, A. (FEI Digital Rock Services) | Young, B. (FEI Digital Rock Services) | Idowu, N. (FEI Digital Rock Services) | Al-Jeri, S. A. (Kuwait Oil Company) | Al-Rushaid, M. A. (Kuwait Oil Company)
A study was designed to confirm the formation properties obtained from available conventional RCA data and inferred from corrected wireline log data using digital rock analysis (digital RCA and SCAL analysis) on cores from the Greater Burgan field. This study was performed for Kuwait Oil Company, Fields Development Group (S&EK) by FEI Digital Rock Services in 2014.
As part of this study, 27 feet of whole core, from the Lower Ahmadi (AHL2) to Upper Wara (WU1) formations, were imaged by X-ray computed tomography (CT) imaging, including 1 foot of partially preserved core. 14 plugs were extracted from these cores and imaged in 3D by a high resolution helical micro-CT. Analysis revealed stark differences in mineralogy, grain size and sorting and the presence of severe fracturing in some plugs due to the fragility and friability of the rock.
Sub-plugs were extracted from 10 of the 14 plugs (including one sub-plug from the partially preserved section) and imaged in 3D by helical micro-CT. 7 of the sub-plugs proved suitable for digital RCA and SCAL analysis. The 3D images were used to calculate digital RCA properties (porosity, permeability, grain density, grain size distribution and formation factor) and pore network models were built to perform digital SCAL simulations and predict multiphase transport properties such as Pc, kr and resistivity index for primary drainage and imbibition.
In addition, the
A tight rock workflow was used to identify sub-resolution porosity in 3 of the plugs. Experimental MICP curves showed that substantial portions of the pore throats were below the image resolution, caused by large amounts of pore-filling materials. Hence, pore scale information could not be directly extracted from some images. Consequently, process based modelling was carried out on two plugs to generate pore-networks. A quasi-static pore-network model was used to simulate oil/water displacements and predict multiphase transport properties. Detailed imaging of oil-in-place and porosity was performed on a partially preserved plug to create a map of remaining oil which revealed that oil was retained in most porous grains and strongly retained in clay-rich zones.
The digital core analysis results are in agreement with available log and core data. The Lower Ahmadi (AHL2) section is good quality in terms of porosity, permeability and flow properties, whereas the Upper Wara (WU1) section is of poorer quality.