For formation tester sampling, it is crucial to obtain clean representative samples of low drilling fluid filtrate contamination. The accurate, real-time prediction of the level of oil-based mud (OBM) filtrate contamination during sampling is essential to ensure that a low contamination fluid sample is obtained. Existing methods rely on the curve fitting technique of single channel/sensor measurements, such as optical, composition, density, and compressibility. These curve fitting methods necessitate a significant signal contrast between the pure OBM filtrate and the formation fluid. Curve fitting uses two assumptions that are often proven untrue: 1) the fluid asymptotically approaches a clean fluid value and 2) the curve fit equation is simple and unchanging throughout the pumpout and can therefore be extrapolated to long times. Accurate knowledge of pure component properties for both fluids is also necessary for curve fitting methods. Unfortunately, the properties of the two endmembers cannot be measured directly, either in the downhole environment or the laboratory. Therefore, existing methods can be highly sensitive to sensor data selection, the estimates of the endmember properties, and the method of curve fitting.
A new reliable multivariate method was developed to accurately determine the downhole sample contamination level using the data stream from multiple sensors. The new multivariable method overcomes all limitations of curve fitting methods. This method treats the downhole sample cleanup process as a mixing problem of the two endmembers and solves the problem by applying reasonable and ubiquitous constraints to the multivariate sensor signals of the mixtures. This method enables data from multiple optical channels or multiple sensors to be fused and then used in a process to accurately and reliably predict contamination. Using this method, accurate knowledge of the endmember properties is no longer necessary to estimate the contamination level. The algorithm automatically weights the contributions of signals based on the contrast of each signal and optimally processes data to generate the properties and concentration profiles of the endmembers, which provides the OBM contamination measurement in real time. This study shows that sample contamination can be measured even when a pumpout has asymptotically reached a higher level of steady-state contamination. The effectiveness and reliability of this method are demonstrated through three field cases in which the predicted contaminations levels closely matched laboratory results.
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.
Steiner, Stefan (ADCO) | Ahsan, Syed Asif (ADCO) | Noufal, Abdelwahab (ADCO) | Franco, Bernardo (ADCO) | Koksalan, Tamer (ADCO) | Amjad, Kashif (ADCO) | Helja, Emina (ADCO) | Alhosani, Sabah (ADCO) | Adesanya, Akindele (ADCO)
ADCO has drilled a number of wells and evaluated hydrocarbon potential of the Middle Cretaceous Wasia Group Unconventional reservoirs onshore Abu Dhabi since 2012. Latest logging and core analysis technologies were applied to assess key parameters such as Total Organic Carbon (TOC), source rock maturity, mineral compositions and fluid saturations, as well as geomechanical parameters such as Young's modulus, Poisson's ratio and minimum horizontal stresses. To date more than 2500ft of core has been extracted, described and analysed. We understand that ADCO has, by far, the largest data base among all the OPCOS with regards to unconventional play and has gained a significant local learning curve ahieved over the last 3 years.
In addition to triple combo data, log data acquired consists of NMR, high resolution lateralog, dielectric logs, and mineral spectroscopy, cross dipole sonic, borehole imaging and sonic scanner, routine and advanced mudlogging. Core analysis consists of crushed rock analysis, pyrolysis and rock mechanics testing. Significantly high mud gas readings, observation of oil staining, odor, and fluorescence under UV light indicate presence of oil over large sections of the acquired cores and side wall cores from various geographically spread wells. Recently, we have conducted 5000 TOC and 1500 Pyrolysis measurements from core and cuttings samples in 110 wells spread all over Abu Dhabi. This data clearly demonstrate that large sections of Wasia Group bear excellent source rock quality in several wells located in large segments of onshore Abu Dhabi. Visual inspection of core and TOC measurements indicate that high frequency jet black centimeter scale organically rich lamellae often exceeding 20% TOC in several wells are not uncommon. The unconventional reservoir rocks are composed of predominantly clean and tight matrix carbonate mudstones and wackestones. Preliminary results of the current exploration campaign within the ADCO concession are very encouraging, showing indications of hydrocarbon presence. Formation testing is planned in the near future to confirm the Unconventional play in Abu Dhabi.
The paper focuses on an integrated multi-disciplinary approach covering petrophysical, geological, geochemical and geomechanical assessment with the ultimate goal to determine optimal parameters for formation testing and production.
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.
Kumar, Sanjeev (Kuwait Oil Company) | Al-Hamad, Hamad (Kuwait Oil Company) | Al-Bous, Faisal (Kuwait Oil Company) | Al-Mutairi, Fayez (Kuwait Oil Company) | Sanyal, Arunava (Kuwait Oil Company) | Safar, Ahmad (Kuwait Oil Company)
A number of heavy oil or tar accumulations have been reported in several Middle East reservoirs. Heavy oil is often overlooked as a resource because of the expense and technical challenges associated with producing it.
But more than 6 trillion barrels of oil in place attributed to the heaviest hydrocarbon. Most of the conventional onshore hydrocarbon reservoirs have been depleted, and time of easy hydrocarbon is over; so, it is prudent to look into the unconventional reservoirs like heavy oil. An accurate evaluation and characterization is obviously crucial to its efficient exploitation. The evaluation and characterization of heavy oil depends on its identification, quantification, analysis of representative fluid sample and reservoir properties.
The methods proposed in the literature might be successful in identifying heavy oil reservoirs but are less reliable for quantifying the amount of heavy oil, and are insensitive to oil viscosity, the key property that controls the producibility of heavy oil. Heavy oil characterization is incomplete without the sampling of fluid in the reservoir environment. It is often desirable to acquire the sample with wireline formation tester tool and integrate the in-situ fluid properties with NMR logs.
In this study we successfully integrate, conventional logs, NMR logs, in-situ fluid sample, PVT data and conventional core data for identification and quantification of heavy oil present in the pore space. This integrated study overcomes the limitations of individual techniques. Our case study shows that the porosity deficit between conventional total porosity and NMR porosity gives the identification of heavy oil present in the pore space, this difference between two porosities represents the extra viscous component of fluid that are not observable by the NMR tool. The amount of porosity deficit is the amount of extra heavy oil / tar in the pore space and this gives the quantification of the same.
Conventional and NMR derived reservoir properties are required to be integrated with conventional core porosity, permeability, water saturation and viscosity derived from PVT sample in order to characterize Heavy Oil in Clastic Reservoirs.
Al-Ibrahim, Abdulla (Kuwait Oil Company(KOC)) | Al-Bader, Haifa (Kuwait Oil Company(KOC)) | Al-Salali, Yousef (Kuwait Oil Company(KOC)) | Duggriala, Vidya sagar (Kuwait Oil Company(KOC)) | Ayyayo, Manimaran (Kuwait Oil Company(KOC)) | Subban, Packirisamy (Kuwait Oil Company(KOC))
Exploration in the state of Kuwait focuses on finding light oil and gas from deeper, HPHT and naturally fractured tight gas and condensate Jurassic Reservoirs. These reservoirs are drilled with high Oil Base Mud (OBM) densities (16–20.8ppg). The existing surface and subsurface constraints resulted in changing the proposed well location, which resulted in changing the well profile from vertical to highly deviated well. Having a deep HPHT well in highly deviated manner causes more complexity while drilling and testing the Jurassic formations. 78.2-degree angle deviated well with several side tracks and two doglegs was drilled to a depth of around 20,000-ft.(MD) to delineate the potential of the deep reservoirs. Well intervention operations were considered potentially risky due to the presence of hazardous well conditions such as HPHT and high H2S concentration. Keeping in view of well profile and hostile environments, it was very challenging task to conduct a short term well testing (STT) in these deep reservoirs.
Tractor was used in the highly deviated sections with more than 50-degree angle to record the cement quality logs with Wireline. The target formations were perforated using high temperature and high shot density TCP guns in overbalance condition using drill-pipe. Two separate Drill Stem Tests (DST) consist of tester valve, multi-cycle circulating valve, two rupture disc valves, Down hole sampler and Down hole memory gauges were used to test two different deep high pressure and sour reservoirs. Using of 15 K Coiled Tubing with total length of 20,000 ft for well activation and stimulation assisted the well intervention during the STT.
Careful planning, proper selection of equipment & materials, detailed well test program and procedures resulted in a safe and successful testing operations in such extreme well conditions such as unconventional well profile, HPHT, and presence of H2S. For the first time in Kuwait, a highly deviated exploratory well with complete set of DST tools was successfully tested and proved significant amount of light oil and gas from a hostile reservoir.
This paper describes and discusses the challenges encountered while drilling and testing an exploratory well and the achievement of overcoming these challenges which leads to successful well testing.
Rajkhowa, Anupam (Kuwait Oil Company (KOC)) | Al-Bader, Haifa (Kuwait Oil Company (KOC)) | Hameed, Waleed Ahmad Abdel (Kuwait Oil Company (KOC)) | Al-Nabhan, Abdul Razzaq (Kuwait Oil Company (KOC)) | Subban, Pakkirisamy (Kuwait Oil Company (KOC))
The objective of this paper is to present the methodology adopted to overcome challenges faced during sampling and characterization of heavy oil in deep exploratory wells.
As a part of exploration activities, two exploratory wells had been successfully drilled and tested in deeper low permeability Lower Cretaceous reservoirs. Drill Stem Test (DST) technique is adopted to test all exploratory wells for collecting production, surface and bottom-hole pressure and temperature data and collection of fluid samples for fluid characterization. As the wells are tested with retrievable packer, coiled tubing (CT) is required during activation and stimulation operations due to absence of other lifting methods. In this case study wells, coiled tubing was lowered and the well was lifted continuously with nitrogen for clean-up and to assess production behavior as there was no self-flow. Surface samples have been checked to assess contamination with diesel used for underbalance operations. Continuous nitrogen lifting helped to collect representative bottom-hole samples.
During testing, there was poor inflow of heavy oil of API 21–22 Deg, but the well could not be produced naturally in spite of repeated attempts. Matrix acid stimulation treatment was done to improve the productivity of the reservoir. Well flowed heavy oil and then gradually ceased to flow. Due to low mobility, self-flow could not be sustained. These pose significant challenges for well cleanup, flow studies and collection of representative sample for PVT analysis and fluid characterization.
Surface sampling was not favorable due to mixing with lifting nitrogen gases and only alternative method available was to collect Bottom-Hole Samples (BHS). However, proper cleanup was an issue for sampling operation. Continuous lifting with nitrogen helped to produce clean oil in both the wells. Compositional analysis was done on the nitrogen lifted sample to quantify the contamination level before lowering the down-hole sampler in order to capture representative BHS. As a result of this approach, representative samples could be captured and fluid characterization could be carried out with quality results. It has been planned to adopt the same methods in such type of situation in testing exploratory wells.
With the systematic approach representative samples could be successfully captured in both the wells where self-flow could not be sustained in spite of repeated attempts. Fluid characterization of heavy oil could be could be carried out in these two exploratory wells which are very valuable for further development planning of the reservoir / field.
Understanding the fluid flow in the reservoir is one of the main factors affecting the success of waterflood projects. The level of reservoir heterogeneity and complexity of the structure are the main challenge factors to understand the fluid movement. Interwell water tracers is a significant approach especially in reservoirs that have high level of complexity to have better understanding of the injected water flow directions, flow units and reservoir geology.
Raudhatain-Mauddud reservoir is highly heterogeneous layered reservoir, bearing different oil qualities. The waterflood started in year 2000 and within a short period the oil rate has increased significantly but with rapid increase in the water cut. The management of Mauddud waterflood project became more complex with increasing the number of injectors and establishing injection in all layers. Interwell Tracers have been utilized to understand the complex injected water movement in the reservoir to improve waterflood management process.
Different conservative water tracers have been injected to track the injected water movement between the wells. Tracer breakthrough has been detected in many producers with wide range of tracer's residence time between the wells. Performance of tracer concentration in the stream of each well versus time has proven the flow through different flow units. The Tracer information has been utilized qualitatively and quantitatively to understand the fluid movement laterally and vertically between the flow units and provided invaluable information that has been used for optimizing Mauddud reservoir waterflood, calculating the swept volume and to optimize wells production.
This paper presents a detailed review of case history for utilizing the Interwell Water Tracer information to understand the fluid flow in the reservoir and the approach to manage Waterflood operations and optimizing wells` production.
Fornasier, Ivan (Schlumberger) | Yasukochi, Toru (JX Nippon) | Gligorijevic, Aleksandar (Schlumberger) | Uchimura, Ryuichi (JX Nippon) | Shirai, Seiji (JX Nippon) | Chai, Zhenji (JX Nippon) | Chouya, Smail (Schlumberger) | Wee, Wa Wei (Schlumberger) | Khanal, Gokarna (Schlumberger) | Haddad, Sammy (Schlumberger)
This work presents case studies in which the integration of Advanced Surface Fluid Logging (ASFL), wireline downhole formation fluid and reservoir fluid samples’ PVT analysis proved to be successful in reducing formation evaluation uncertainties and driven the subsequent decisions about the completion and production plan.
ASFL analysis was effectively used during the drilling of exploration wells, to provide early formation fluid evaluation, which was then utilized to optimize wireline formation fluid sampling and Drillstem Test (DST) perforation intervals. Identification from ASFL analysis of multiple fluid contacts revealed a much greater complexity of the targeted reservoirs, which in turn was not evident from the standard LWD formation evaluation techniques. The fluid type and fluid contacts calls from ASFL were then confirmed by the wireline downhole fluid analysis, DST and later on by the PVT results. Fluid composition was found constantly in agreement among the different techniques and the ASFL fluid fingerprints were eventually utilized as reference in the field for real time fluid type assessment