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.
Sabiriyah Mauddud, has been on water flood since Dec 2000 with seawater. Reservoir souring is the in-situ generation of H2S in the reservoir itself due to waterflood operations using seawater. Traditionally, Mauddud is a sweet reservoir & some degree of reservoir souring occurs due to Sulfate-Reducing Bacterial (SRB) activity. As a new initiative for tracking souring, H2S coupons were used for the first time in Kuwait at one of the EOR wells in open hole condition during drilling. This has been extended to flowing wells as part of the FBHP survey so that the coupons reflect H2S levels nearest to Mauddud perforations, using the slick line, for the first time in the industry, to detect micro H2S levels.
Different methods are used to measure H2S concentrations such as WH samples or titration / dragger tubes from needle valve (separator unit) for surface sampling, or taking bottom hole sample using conventional sampling chamber which is usually made from stainless steel material, normally reactive with H2S.
It is a challenge to accurately measure low ppm levels of H2S in formation fluids where there is a risk of not capturing these concentrations using conventional samplers/ sample bottles because of the reaction between H2S and sample chamber during bottom hole sampling operation. Therefore, non-reactive coated sampling bottles were recommended and used in the past. The option of H2S coupons to be used as slick line operation is one of the key improvements in tracking H2S without loss of tiny content of H2S via adsorption in wellbore/ flowline transit.
With H2S coupons, certain metal alloys discolor, as a result of corrosion, only due H2S. These alloys are said to be "Specific" to the presence of H2S. Discoloration due to H2S is weakly dependent on temperature and exposure time. Discoloration results in loss of the original shiny or glossy finish. This phenomenon is largely a function of partial pressure, not concentration. This is true for both gas phase and liquid phase. Hence, the H2S coupons measures the total H2S for the reservoir fluid.
SA-X is a vertical well in Sabiriyah Mauddud equipped with Y-Tool. H2S coupons were run to detect H2S levels across Mauddud. Two sets of H2S coupons were placed inside the bottom of the tool along with pressure and temperature sensors. Consistent results were obtained from both H2S coupons sets. Only the high sensitive coupon was affected indicating H2S partial pressure higher than 0.005 but less than 0.018. H2S level is found in the range between 5 – 15 ppm which is quite close to what has been measured in the lab during compositional analysis during PVT studies for monophasic fluid. This has built team's confidence regarding the validity of the data via souring coupons. This procedure has now become part & parcel of our routine surveillance activities for tracking reservoir souring.
The procedure has added a simple but accurate fit-to-purpose tool for tracking reservoir souring in North Kuwait.
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.
Dekker, R. (Shell Global Solutions International BV) | Tegelaar, E. (Shell Global Solutions International BV) | Perrotta, S. (Shell Global Solutions International BV) | Miller, S. D. (Shell Kuwait Exploration & Production) | Le Varlet, X. (Shell Kuwait Exploration & Production) | Hasler, C-A. (Shell Kuwait Exploration & Production) | Narhari, S. R. (Kuwait Oil Company) | Rao, J. D. (Kuwait Oil Company) | Neog, N. (Kuwait Oil Company) | Dwindt, A. A. (Kuwait Oil Company) | Al-Haidar, S. (Kuwait Oil Company) | Dashti, Qusem (Kuwait Oil Company)
The primary objective of the present study is to determine the fluid connectivity in the Middle Marrat of the major Jurassic fields in North Kuwait. Understanding fluid connectivity on both geological and production time scales has a direct impact on static and dynamic reservoir modeling, history matching, fluid property variations during production and zonal allocation of comingled production.
123 light oils and condensates were analysed using multi-dimensional gas chromatography (MDGC). The resulting so-called fluid fingerprints were interpreted in the context of a complex geological framework resulting from extensive sedimentological, petrographic, and structural geology studies. A detailed description of different fluid families allowed reconstruction of reservoir connectivity on a geological time scale. Fault transmissibility was reconstructed from the distribution of fluid fingerprints of samples taken during well tests or/and early production representing the fingerprint of the initial fluids in place. Also, the significance and extent of baffles to vertical fluid flow like anhydrites or low permeability streaks could be evaluated.
In time-lapse-geochemistry, fluid fingerprints are monitored during production. Changes in fluid fingerprints were interpreted in terms of fluid movement from other reservoirs along fault systems. These changes in fluid fingerprints matched the changes in fluid properties observed during the well testing. In other examples, changing relative contribution of different separate flow zones that are commingled in the subsurface were recognized.
The results are used to update/constrain the 3D static & dynamic models. Results help to understand connectivity, fluid flow and Pore Pressure Prediction (PPP) for new wells to be drilled.
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.
Dernaika, Moustafa R (Ingrain Inc) | Sahib, Mohammad Raffi (Kuwait Oil Company) | Gonzalez, David (Ingrain Inc) | Mansour, Bashar (Ingrain Inc) | Al Jallad, Osama (Ingrain Inc) | Koronfol, Safouh (Ingrain Inc) | Sinclair, Gary (Ingrain Inc) | Kayali, Anas (Ingrain Inc)
Detailed core characterization is often overlooked in the sampling process for core analysis measurements. Random core sampling is usually performed and the selected plugs are not associated with rock types or the reservoir heterogeneity. The objective of this study is to obtain representative samples for direct simulation of petrophysical and fluid flow properties in complex rock types.
A robust sampling strategy was followed in reservoir cores from two successive heterogeneous carbonate and siliciclastic formations in the Raudhatain field in Kuwait. The sample selection criteria were based on statistical distribution of litho-types in the cores to ensure optimum characterization of the main reservoir units. The litho-types were identified based on porosity and mineralogy variations along the core lengths utilizing advanced dual-energy X-ray CT scanning. High resolution micro-CT imaging and subsequent segmentation provided 3D representation of the pore space and geometric fabric of the core samples. Primary drainage and imbibition processes were simulated in numerical experiments using a pore-scale simulator by the Lattice Boltzmann Method. Capillary pressure (Pc) and relative permeability (Kr) curves together with water and oil distributions were investigated for complex geometries by the different rock types.
The dual energy CT density was compared with wireline log and provided accurate calibrations to the downhole logs. The different rock types gave distinct capillary and flow properties that can be linked to the rock structure and pore type of the samples. The Lattice Boltzmann based pore-level fluid calculations provided realistic fluid distributions in the 3D rock volume, which are consistent with pore-scale physical phenomena.
This characterization method by the dual energy CT eliminates sampling bias and allows for each cored litho-type to be equally represented in the plugs acquired for subsequent petrophysical and fluid flow analyses. It also provides accurate calibration tool for downhole logs. The digital analysis gave reliable SCAL data with improved understanding of the pore-level events and proved its effectiveness in providing advanced interpretations at multiple scales in relatively short timeframes.
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.
Ibemere, Uche (Laser Engineering and Resources Consultants Limited, Port Harcourt, Rivers State) | Mmata, Bella (Laser Engineering and Resources Consultants Limited, Port Harcourt, Rivers State) | Onyekonwu, Mike (Department of Petroleum Engineering, Unversity of Port Harcourt, Rivers State)
Crude oil fingerprint analysis is an investigative technique which can be employed during exploration and production to yield useful geochemical parameters, needed by the geologist, production engineer and oil spill management specialist. This analysis can give clues on depositional environment, thermal maturity, oil biodegradation and even aid production allocation.
In this work ten crude oil samples from the Niger Delta region of Nigeria were analyzed. The analysis was done with Gas Chromatographic instrument equipped with flame ionization detector (GC-FID) and HP-PONA capillary column. The standard method used was based on ASTM D2887. In-house developed mathematical tools, such as star diagrams and production allocation graph were used to estimate the required geochemical parameters.
The results of the analysis suggest that 50% of the analyzed samples were from oxic paleoenvironment which their ratios (above unitary (1)) indicated; 70% of them have predominance of odd carbon in their make-up, with carbon preference index (CPI) value above 1, while 60% of the analyzed crude oil samples were thermally immature. The outcome of this work can be used to estimate production allocation quota, identify culprit sample in time of spill incident and dispute between operators in a cluster area. Furthermore, it is an economical means of crude oil characterization when compared to other techniques.
With the onset of water production, mineral scale deposition appears in the oil and gas wells. The scale deposition in wellbores and flow lines is a universal challenge that has to be addressed with technical and economical effectiveness. Efforts are ongoing to effectively inhibit the scales or remove them through chemical or mechanical means.
Kuwait Oil Company is planning to improve the production to 4.0 MM BOPD by the year 2020. In this pursuit, all the possible efforts are made to increase production including application of new technology in drilling, completion, well production and facilities. One of the key aspects of production improvement from individual wells is to avoid any obstruction in the wellbore, wellhead and flow lines that might affect the smooth flow of hydrocarbons. This includes the augmented steps on eliminating mineral deposition from wellbore and flow lines.
The wells are suffering from frequent scale deposition in wellbore and flow lines. Usually these problems are mitigated by using strong acid. However, due to maturing of field the wells are generally completed with ESPs. When acids like HCl are used, these ESPs are corroded severely adding extra cost of workover and production loss. This challenge is driving the operators to use less aggressive chemicals that remain environmentally friendly and can maintain the integrity of submersible pumps, metallurgy of the flow lines and other components.
To meet this challenge, various chemicals were evaluated through laboratory tests and case histories. The chemical composed of Glutamic acid was selected for the first pilot. The pieces of tubular and other well components suffering from scale deposition were tested in the lab and the results were found to be highly encouraging. Based on this a pilot campaign was initiated with a batch of eight wells to treat wellbore and flow lines. All the treatments were found highly successful. Due to this treatment, the daily production has been improved to 5,000 BOPD without any extra activity such as replacement of ESP or flow line tubing due to corrosion.
The paper presents the technology evaluation process, lab testing and field trial results.