Cig, Koksal (Schlumberger Middle East SA.) | Kristensen, Morten Rode (Schlumberger Middle East SA.) | Thum, Sebastian (Schlumberger STS) | Ayan, Cosan (Schlumberger) | Mackay, Eric James (Heriot-Watt University) | Elbekshi, Amer (Abu Dhabi Company for Onshore Oil Operations) | Naial, Radwan (ADCO)
A multilayer carbonate reservoir, having medium to low permeabilities with distinctive oil-water contacts, is in an appraisal stage. Large data gathering including rigorous coring is underway in the field. It is identified that the slowest part of the data evaluation is generally SCAL analyses due to its laborious workflow. A new approach is proposed by introducing a wireline formation tester (WFT) multiphase flow analysis to obtain relative permeabilities. The WFT tool is commonly used in this field to measure pressures and collect samples. In this paper we present a novel methodology for estimating in-situ relative permeability curves with the help of available WFT multiphase flow data and its numerical optimization.
During drilling of a well the formation is exposed to mud filtrate invasion. The invasion displaces oil in the vicinity of the wellbore, much like a small water flooding experiment in the case of immiscible mud filtrate and formation fluid. A WFT sampling operation in a multiphase flow environment provides an opportunity for determining related properties by utilizing bottom-hole pressure and water-cut data. A numerical model replicates the mud filtrate invasion and sampling with reservoir properties and WFT tool geometry. The numerical simulation model consists of a proper definition of reservoir properties as well as WFT tool geometry, including size and shape of flow inlets, along with tool storage and fluid segregation effects. The model is embedded in an optimization workflow and relative permeability curves, damage skin and depth of mud filtrate invasion are then estimated by minimizing a misfit function between measured and modeled pressures and water-cuts. The relative permeability curves are parameterized using industry accepted models. The optimization workflow uses a distribution function of response parameters where the entire parameter range is included in the numerical runs, thus ensuring that a global optimum is found. Initial parameter estimates are determined from open hole logs, such as resistivity, dielectric, magnetic nuclear resonance and from pressure transient analysis.
The methodology developed in this paper is validated by application to a synthetic dataset with a known solution, and it is subsequently demonstrated on actual field data from a WFT sampling operation. The results of this paper demonstrate that it is possible to reliably estimate multiphase flow properties from WFT sampling data. The key contributions of this study are to show the capability of estimating a variety of multiphase flow properties from routine WFT cleanup data and to establish an automated approach, including a novel inversion methodology, to reduce the turnaround time.
A WFT sampling or cleanup operation in a multiphase flow environment gives an opportunity for determining in-situ relative permeabilities and capillary pressures in an inversion workflow by utilizing data recorded downhole. We describe a methodology to estimate multiphase flow properties with the help of numerical simulation and optimization. The numerical simulation model for the mud filtrate invasion and cleanup consists of a proper definition of reservoir properties as well as WFT tool geometry, including size and shape of flow inlets, along with the tool storage and fluid segregation effects. The numerical simulation model mimics the invasion, cleanup and pressure transient events.
Jacob, Claire (Schlumberger Tech Services) | Dutta, Dhrubajyoti (Schlumberger STS) | Grau, Jim (Schlumberger) | Abangwu, Prince (Schlumberger Tech Services) | Baig, Mirza Hassan (Schlumberger) | Saikia, Prodip Kumar (Sonangol P&P) | Santos, Celia Maria (Sonangol P&P) | Contreiras, Kilamba Diogo (Sonangol P&P)
Accurate characterization of fluid and pressure regimes within a reservoir is a crucial part of the overall reservoir description process. In many offshore exploration and appraisal wells this task is performed using data acquired with wireline formation testers (WFT). Significant planning and simulation is required to properly design a WFT program. This is especially true when the anticipated environment is different from that normally encountered in the local region. Collaboration with a wider group of experts is required. Secondly, an iterative approach to the acquisition of WFT data is required, in which the results of the previous step determine the next step.
This paper describes the process for WFT data acquisition within a major service company. We focus on two key aspects. First is the networked collaboration of domain experts around the world who are used as a resource for any given situation. Communication tools, sharing models, and networking options are discussed. Secondly, we examine the processes for real-time interactive communication with the wellsite and relevant stakeholders. Data transmission, real-time integration into reservoir models, and tools for operational interface are discussed.
Finally we show field examples of these processes in use. In one example we document the gathering of best practices for sampling heavy oil in West Africa (heavy oil is a relatively rare occurrence in this region and sampling required the input of expertise from other regions). In a second example, we show the use of collaborative tools to optimize data acquisition for accurate reservoir characterization in the case of an exploratory well that encountered fluids very different from predrill expectations. And finally we show an example of using Interval Pressure Transient Testing (IPTT) and Vertical Interference Testing (VIT) data to economically pre-empt the acquisition of expensive DST data.
The acquisition of quality samples from heavy oil reservoirs can be especially critical. It is frequently the case that in these environments the quality of the oil is the single biggest reservoir risk. Therefore a valid fluid sample where accurate measurements of parameters such as gas oil ratio and viscosity can be made is crucial. These sample can be acquired with production tests but, as in many reservoir environments, it is often desirable to acquire these samples with formation tester (WFT) tools. However, heavy oils provide a significant challenge for WFT's. The oils are of high viscosity which results in large drawdowns while flowing. They are frequently located in shallower, unconsolidated reservoirs where high drawdowns can lead to sand failure. And additionally they can combine with water (from the formation or from the filtrate) to form emulsions that make fluid analysis difficult and can degrade the quality of the acquired sample.
In this paper we review the elements required for successfully sampling heavy oil reservoirs with WFT tools. We first consider the pre-job modeling that is performed to predict the drawdowns and flow rates that can be expected from assumed reservoir properties. We then use this information to design the appropriate tool string from the myriad of options available today. We look at the variety of hydraulic pump and displacement unit options that afford a wide range of flow rates and therefore control over drawdown. Additionally we look at the probe and packer configurations that allow a wide variety of flow areas, again giving more control over sandface drawdown. Finally we address the issue of emulsions especially as it applies to downhole fluid analysis and how these can be mitigated.
An increasing number of deviated wells are being drilled to maximize production and hydrocarbon recovery in the mature reservoirs of the Gulf of Suez (GoS). Successfully drilling a high-angle well in a tectonically disturbed and structurally complex area like the GoS is very challenging, especially in depleted reservoirs. Selecting the optimal mud weight is absolutely essential. Stress orientation and magnitude also have a major impact on wellbore stability.
The region poses significant drilling challenges that vary widely from reactive shale and salt creep to stress-related instability. From the findings of multiple wellbore stability projects we conducted in the GoS, we review the dominant mechanisms of wellbore instability in the GoS. We provide a summary of the failure mitigation measures and an overview of stress magnitude and orientation in the region, demonstrating how it impacts the knowledge of the most stable drilling direction.
Understanding the main causes of rock failure in the GoS resulted in improved drilling efficiency and reduced drilling costs. We show an example, where a new, nearly horizontal (86º) well was successfully drilled through the Asl formation with less than half a day of non productive time during the entire drilling process.
We conclude that acquisition of new, high-quality data would considerably reduce the uncertainty surrounding drilling complex wells in the area and reduce their cost.
Borehole instability, in most of the cases, is a direct reflection of earth's in situ stress state. It is well known that the stress distribution around the wellbore induces deformation depending on many factors ranging from wellbore pressure history and rock strength to the trajectory orientation.
A stress direction map is generated for the GoS from observations of borehole breakout detected in multi-arm-caliper logs and other log data base, viz., electrical Images and sonic logs. In vertical wells, the maximum tangential stress around borehole can produce breakouts and their orientation indicates the direction of minimum in situ horizontal stress (Sh). In the case of deviated wells, a stress-tensor diagram defines Sh direction with reasonable accuracy, provided wells cover wide range of deviation angle and azimuth
The current study indicates that Sh in GoS is aligned along two major trends. The main NNE - SSW trend, with average orientation of N10degE, exists in most of the region.The second trend is aligned NE - SW and observed locally at the central eastern and south-western part of GoS, with an average orientation of N50degE. Most studies of the structural and tectonic history of the GoS have identified two age significant orientations for this extensional rift. The early to middle Miocene rifting, responded to a Sh direction of N55-60degE (rift-climax). The younger stress fields of the Late Miocene and Pliocene times rotated progressively counterclockwise to a N15-25degE direction that persisted into early-late Pleistocene time. The dominant in situ stress orientation trend, identified in this study, therefore, is mainly controlled by this younger stress field of the GoS rifting.
In situ stress directions have strong impact in drilling high angle wells in GoS. Proper placement of well trajectory with respect to in situ stress reduces instability in drilling. The paper exhibits example of directional sensitivity of well trajectory and successful drilling campaign based on the developed stress map.
Orlandi, Aristides Neto (Schlumberger Logelco, Inc) | Hassan, Saad (Belayim Petroleum Company) | Dutta, Dhrubajyoti (Schlumberger STS) | Mohie, Mohamed (Belayim Petroleum Company) | Biagi, Mario (Belayim Petroleum Company) | Fasto, Alessandro (Belayim Petroleum Company)
As the global power scenario changes with increased demand for oil and gas, remote and challenging (deepwater offshore, high pressure-high temperature, high-angle wells) locations are drilled in an ever-demanding exploration effort with minimum or no experience in the area. To meet the demand and associated financial implications, operators are drilling high-angle wells that require special care from well stability, completion, and formation evaluation, to name a few. Complex reservoirs require complex trajectory and therefore proper well placement. To place a well accurately, the evaluation of acquired data requires real-time interpretation. In Egypt, Petrobel is following the trend and has been drilling deviated wells to enhance production in the Mediterranean by using a new logging while drilling (LWD) platform for formation evaluation. The data delivered by this service includes not only traditional measurements such as resistivity, density, neutron porosity, gamma ray, and caliper, but also induced spectroscopy and sigma. The sigma measurement is used for saturation evaluation independent of resistivity. The availability of two independent saturation estimations provides additional confidence. Spectroscopy provides formation mineralogy and accurate clay fraction, which enhances shaly sand interpretation. Formation evaluation in real time provides accurate estimates of hydrocarbon in place and allows for comprehensive decision making. The field is approximately 70 km from the coast of Alexandria, Egypt. The main reservoir is predominantly sandstone with gas and condensate. Highlighted in this study:
The detection and evaluation of reservoir connectivity and compartmentalization continues to be a significant issue in reservoir characterization, especially in offshore fields that must commit significant upfront costs before production can begin.
It is generally accepted that with most of the petrophysical and formation testing measurements made in the borehole we are able to detect reservoir separation but we are not able to prove connectivity. That is, we can prove the negative but not the positive. However, compartmentalization (proving the negative) can economically doom a project. Therefore it is incumbent upon the practitioner to incorporate and integrate all measurements, including logs, pressure measurements and PVT data, before passing judgment.
In the example discussed in this paper, multiple wells are being drilled as injectors. Connectivity to the producer wells is critical. We evaluate acquired pressures and gradients from formation tester tools in several of these wells. Additionally PVT quality samples were obtained and PVT data from these samples is incorporated intothe analaysis. Compartmentalization within a reservoir can be either vertical, lateral, or both. Evaluation of vertical connectivity can be done by either evaluating pressure or fluid discontinuities. The use of pressure discontinuities is well established. To use fluid discontinuities we assume that fluids in flow communication over geologic time will equilibrate to a predictable fluid gradient. Fluid distributions that are not predictable can be suspected to be not in flow communication and further investigation is warranted.
For lateral connectivity, we evaluate well-to-well data. Formation pressures and samples were obtained from the producer and the injector well. We show how to calibrate the response between different tools in different wells and then describe how the differences can be resolved. Again a statistical analysis of the pressure gradient data is applied to ensure that any inferences made are sustainable given the accuracy, resolution, and repeatability of the acquired data.
Block 4 is located at the southern margin of the lower Congo Basin. The area is characterized by detached Cretaceous rafts gliding on a continuous bed of salt, divided by thick Tertiary sedimentary grabens which indicate salt movements until the present day. The Gimboa field is located in the middle part of the continental slope in an area with numerous turbiditic events which occurred during the Miocene period. A general geological crosssection showing the stratigraphy in the area is presented in Fig. 1.
The acquisition of quality reservoir fluid samples is crucial for the correct evaluation of reserves and for the design of productions facilities. Very frequently these samples are acquired with a production test, but in many cases there is no DST or it may not test all potential zones. As a result the industry has an increasing reliance on samples acquired with Wireline Formation Testers (WFT). These samples, however, come with an important caveat. In wells drilled with oil base mud the invading filtrate can contaminate the acquired sample to the point where results from laboratory measurements may be uncertain or even useless.
A recently introduced focused probe technology for WFT tools has greatly improved the quality of oil samples acquired in wells drilled with OBM and has also reduced the time to acquire them. This probe has been very successfully deployed in a number of locations in the world including the Gulf of Mexico and the North Sea where very low or negligible contaminations have been reported. However, deployment has been more tentative in higher mobility poorly consolidated reservoirs such as the Deepwater Tertiary reservoirs of West Africa. In these environments unconsolidated sands frequently fail and partially plug the probe which can reduce the effectiveness of the focusing. Additionally, clean-up can often be quite fast with a conventional probe and can produce acceptable quality samples so the case for the focused probe is less obvious.
However, rising rig spread rates and the need for ever cleaner samples dictate that the speed and quality of focused samples needs to be realized. Additionally, not every reservoir in West Africa is a Deepwater Tertiary. Much production (and exploration) still takes place from low permeability carbonate and carbonate rich reservoirs.
In this paper we examine focused probe sampling results from wells drilled in very high mobility, unconsolidated reservoirs in Nigeria and Angola as well as lower permeability carbonates. We will discuss the hardware choices and reasoning for implementation with a particular emphasis on the use of low rate pumps to minimize drawdown and sanding. We additionally discuss the special filters implemented to reduce plugging. In several of these examples laboratory measurements indicated the acquired samples had no detectable levels of contamination.