For a deepwater operator facing the challenges of directional drilling and wellbore stability, surveying with high spread costs in excess of USD 1 million per day, any approach which promises to reduce or eliminate cost and risk has great potential benefit. This paper showcases how careful planning, a fit-for-purpose survey program, and, most importantly, an effective, real-time geomagnetic referencing service (GRS) can significantly improve the operator's ability to hit both geological and financial targets. The authors describe recent breakthrough improvements in the accuracy of GRS techniques and present a case study to illustrate the benefits of this approach for the industry, especially in deepwater operations.
Each magnetic survey tool has an associated degree of uncertainty in the accuracy of data acquired. This error is cumulative, increasing with depth as a well is being drilled. In three dimensions, this area of uncertainty takes an elliptical form around the projected well path, a zone of possible well positions known as the ellipse of uncertainty (EOU). In high-angle wells, the EOU may grow so large that it exceeds the dimensions of the geological target, decreasing the driller's level of confidence and increasing the risks and potential costs of missing the target. Therefore, the development of more accurate yet cost-effective surveying techniques has become increasingly critical.
The authors will describe a survey approach that meets this challenge by incorporating breakthroughs in real-time GRS and which offers the producer the following benefits:
- Achieving planned geological targets
- Saving the cost of running gyroscopic surveys
- Avoiding costly post-gyro well path corrections by staying on-path in real time
- Preventing stuck pipe, lost time, and other risks often associated with gyro surveys
The example case to be discussed illustrates how to realize all of the above benefits.
Luo, Shanqiang (Hess Corp.) | Wolff, Martin (Hess Corp.) | Ciosek, Jessica McDonough (Hess Corp.) | Rasdi, Mohd Faisal (Hess Corp.) | Neal, Lane (Texas A&M University) | Arulampalam, Pathman (Hess Corp.) | Willis, Sean Kristofor (Hess Corp.)
It is widely accepted that unconventional resources hold enormous reserve potential. However, complex fluid flow physics and completion/stimulation practices pose a unique challenge in estimating reserves or making long-term production forecast for these unconventional reservoirs, as traditional methods are most often not applicable. This paper proposes the application of a probabilistic reservoir simulation workflow to provide realistic range of production forecasts with successful application in the Bakken unconventional tight oil reservoir. First, geomodels are constructed and ranked. Then, key static and dynamic uncertainty parameters are identified for the subsequent history-matching study (with each of the geomodel realizations) that provides not only production forecast for individual wells but also parameter ranges for experimental design (DoE) for field-level prediction. Then, DoE simulations are conducted to construct proxy equations that are used in Monte-Carlo simulations to generate Low-BTE-High response S-curves for the field-level models. Finally, based on these S-curve results, Low-BTE-High deterministic reservoir simulation models are constructed to generate corresponding long-term production forecast profiles for full-field development and optimization.
Over the last decade, an industry wide shift to unconventional plays has occurred due to advances in technology allowing for the recovery of previously uneconomic reserves. The primary objective of completions in these unconventional reservoirs is to increase the effective surface area of the well to maximize reservoir contact. Horizontal drilling and multi-stage fracturing are two technologies which have accomplished this. The two main methods of horizontal, multi-stage completions currently used in unconventional reservoirs are: cemented liner "plug and perf" and open hole, multi-stage fracturing systems.
This paper provides an introduction to unconventional reservoirs, describes the main methods of horizontal, multistage completions, and discusses how the choice of method can affect good fracturing practices as well as long-term production. Case study examples are presented from a variety of unconventional reservoirs included including shale, tight sandstone and carbonate formations.
Operators working in a number of unconventional reservoirs, such as shales and other tight rock formations are experiencing faster than expected production decline rates, resulting in reduced long-term, ultimate recovery. This may be in part due to the abandonment of good fracturing practices, developed over the past 50 years, with the advent of horizontal, multi-stage fracturing. Issues such as near wellbore conductivity, flowback, and fracture tortuosity that can have a significant effect on the long-term production of wells need to be considered when choosing a completion method, particularly for unconventional reservoirs.
Unconventional plays are becoming a significant part of the oil industry today and will become a bigger part in the future. It is important that the reservoirs are completed optimally to make them as productive as they can be. The information provided in this paper is applicable to unconventional resource plays worldwide.
Time-Lapse seismic attributes has been showed as a promising tool to be used in the history matching process. The most common seismic attribute used to integrate these data is P-impedance. The procedure usually made is a minimization of the differences between the seismic P-impedance and the synthetic P-impedance computed from the flow simulation data through a forward modeling. On this paper, we propose a methodology that goes in the opposite way. We invert the seismic data to pressure and saturation and then incorporate these results in the history match procedure in order to integrate the inversion process with the flow simulator, using the results of the reservoir simulation to guide the process. Another feature is that instead of using only the P-impedance in our inversion procedure we are also taking into account a second seismic attribute the S-impedance, which is more sensitive to pressure than saturation variations. A discussion is presented regarding the results obtained using a model with characteristics similar to the Brazilian offshore fields and synthetic seismic data. The main contribution of this work is the integration of the seismic attributes inversion and reservoir simulation processes. We also show the advantages of the inversion procedure to obtain pressure and saturation considering prediction of petroleum production and the details used in the methodology to avoid multiple combinations of saturation and pressure in the inversion process.
Seismic data incorporation in reservoir simulation models history matching (HM) studies has been continuously growing. 4D seismic data, in contrast with well production data, can provide a very good scenario of fluids arrangement along reservoir. In this work we describe how 3D and 4D seismic data gathered in acquisitions performed in Campos Basin was incorporated in Marlim Sul deep water field geological model reconstruction and in assisted HM (AHM).
It is taken advantage of both 3D and 4D seismic data in several stages of the study, for instance, in the construction of a new porosity - most influential in impedance - model by using a methodology based on the inversion of synthetic seismic (calculated by petro-elastic model) in porosity through an optimization process that aims to reduce the difference between observed and synthetic impedance, and when defining influential parameters based on fluids displacement registered by seismic signal, by using a technique based on the creation of transmissibility multipliers parameters regions that considers the fluids displacement shown in 4D signal. Another relevant point is the use of information from reservoir and 3D seismic data when weighting the 4D data in the objective function.
Combining the above mentioned techniques with the knowledge of the field - supported by the 3D seismic data - which allowed, for instance, identification of faults - where fault transmissibility multipliers were used as parameters in the HM process - a fairly good agreement on the observed well and seismic production data was achieved.
HM studies using AHM tools have been shown a much more time-efficient technique when compared to manual HM. The incorporation of 4D seismic data can considerably improve the HM quality by improving the reservoir description, once it increases the ability of describing fluids arrangement and pressure distribution. The techniques successfully applied in the Marlim Sul field HM support these conclusions.
Winarga, Kanuga (EMP Malacca Strait) | Dewanto, Christianto Widi (Caltex Pacific Indonesia) | Erwin, Erwin (EMP Malacca Strait) | Gholib, Ramadanus (EMP Malacca Strait) | Wahono, Teguh (EMP Malacca Strait/Kondur Petroleum S.A.)
Historically, squeezing cement into 9 Interval Perforations in one procedure is almost never happen in actual operation but in August 2010 we did it in Mengkapan Field and finish with success.
Previously in the Melibur oil field in Sumatra, Indonesia, three or four cement-squeeze jobs have been required before the zone holds pressure. Failure was thought to be due to gaps remaining after the squeeze-cementing job between the oil-wet matrix rock and the water-based cement.
This paper will tell a success story in Mengkapan Field by squeeze out 9 interval perforations (850 ft height) in one shot with a surfactant soak that was used to increase the squeeze-cementing success rate. The function of the surfactant was to mobilize trapped oil by creating an emulsion, and to change the oil-wet rock to water-wet rock.
The surfactant was injected into the rock formation and allowed to soak for 24 hours. Then the squeezecementing job was performed as usual. This surfactant soak was trialed in three wells, and they passed the pressure-holding test after an average of two squeeze-cement jobs.
It was concluded that surfactant treatment is a great solution to increase squeeze cementing quality, and is now standard practice in this field.
Pasca-trial and error water shut off program with squeeze cemented watered-out-perforation zone in several onshore shallow wells, more bigger challenge is how to apply into high profile well such in offshore. In company's contract area, there is one offshore field with +/- 6000 ft measured depth and many of interest zones.
After so many years, almost all of interest zone has already perforated. With those conditions, one of the ways is drawdowning the well dramatically to flow the oil to surface. And in some point if some how the artificial lift system (such as ESP) fail, the well will lost their economical value (the oil rate is no longer cover operating cost well) to be workovered.
Poor macroscopic sweep efficiency can be a problem in CO2-flooding of oil reservoirs. The macroscopic sweep efficiency can be low due to the combination of high mobility ratio, gravity segregation and heterogeneity. By decreasing the mobility of CO2 the macroscopic sweep efficiency can be improved. In the present work the surfactant, alpha olefin sulphonate (AOS), has been used as CO2 foaming agent. Dynamic flooding experiments have been carried out at realistic reservoir conditions to study the relative transport of water, CO2 and surfactant when foam is generated in the porous network. The surfactant has been labeled with the radioactive sulfur isotope 35S. The water has been labeled with the radioactive hydrogen isotope tritium (3H) and the CO2 has been labeled with the 14C isotope.
It is shown that the flow of the individual phases in a CO2-foam flooding can be monitored by using of tracer technology. Variations in the flow rates of surfactant solution and CO2 can be clearly detected, and the accessible pore volume can also be determined. AOS products contain different chemical structures. In the study, the main AOS components have been chemically separated prior to injection on the porous column. The transport of the individual components was shown to be different. In the reservoir, chromatographic separation of the AOS components may change the efficiency of the foam process.
The study has shown that use of tracer technology can be a powerful tool in study of transport mechanisms in CO2-foam flooding.
Significant hydrocarbon volumes are present in heterogeneous, low permeability, HPHT reservoirs in the Central Graben area of the North Sea. In order to properly appraise these accumulations, an innovative appraisal strategy is required, which has to dovetail with hazard management and cost containment. In order to lower development risks these may include elements such as an extended well test and permanently installed optical distributed temperature sensor (DTS) system to monitor the flow profile.
A case history is presented of a recent appraisal well drilled on the Acorn discovery, UKCS block 29/8 in the Central North Sea. Significant STOIIP has been mapped in the continental sandstones of the Triassic-age, Skagerrak formation, where reservoir connectivity and resulting commercial productivity was the key uncertainty. A high-angle well was drilled to maximise reservoir exposure, and completed with a DTS system to monitor inflow from different layers. An extended well test was conducted and 50,000 bbls withdrawn. A data-logging device was left on the wellhead to record pressure build-up. The DTS system provided continuous flow profile information.
Well construction, completion and flow testing was successfully achieved on time and budget and was a credit to the meticulous planning and execution by the Centrica wells' team. The required dataset was acquired for the subsurface team, much of it in real-time.
Ultimately a decision to not develop the accumulation was taken following evaluation of all data from the well. Data collected showed reservoir connectivity to be too low to support a development. Percolation theory suggests that a threshold value of N:G constrains the reservoir type encountered. The discovery appraised is interpreted to be below this threshold; however the information collected is pertinent for determining the viability of other such discoveries.
Khosrokhavar, Roozbeh (Delft U. of Technology) | Elsinga, Gerrit (Delft U. of Technology) | Mojaddam, Ali (Delft U. of Technology) | Farajzadeh, Rouhollah (Delft U. of Technology) | Bruining, Johannes
Efficient storage of carbon dioxide (CO2) in aquifers requires dissolution in the aqueous phase. Firstly, the volume available for gaseous CO2 is far less than for the CO2 to be dissolved in the water initially present in the aquifer. Secondly, the partial molar volume of CO2 in the gas phase is about twice as large as the partial molar volume of CO2 in water, meaning that storage in the water phase leads to less pressure increase per amount of sequestered CO2. Transfer of CO2 from the gas phase to the aqueous phase would be slow if it were only driven by diffusion. However, dissolution of CO2 in water forms a mixture that is denser than
the original water or brine. This causes a local density increase, which induces natural convection currents accelerating the rate of CO2 dissolution.
This study presents a set of high pressure visual experiments, based on the Schlieren technique, in which we observe the effect of gravity-induced fingers when sub- and super-critical CO2 at in situ pressures and temperatures is brought above a liquid, e.g., water, brine or oil. A short but comprehensive description of the Schlieren set-up and the transparent pressure cell is presented.
The initial experiments are confined to bulk-phase situations, i.e., in the absence of a porous medium. The experiment is able to demonstrate the initiation and development of the gravity induced fingers. The concentration gradient is high near the gas-liquid interface. The experiments show that natural convection currents are weakest in highly concentrated brine and strongest in oil. The set-up can screen aqueous salt solutions or oil for their relative importance of natural convection flows.
Effective storage of carbon dioxide (CO2) in aquifers requires dissolution of CO2 in formation brine as the virtual density of dissolved CO2 in water (1333 kg/m3) is more favorable than its density in the supercritical gas-phase. Without dissolution of CO2 in the aqueous phase the storage volume of CO2 in aquifers would be of the order of 2% of the reservoir volume. It can be expected that, due to buoyancy forces, injected CO2 rises to the top of the reservoir forming a gas layer. Transfer from this gas layer to the aquifer below would be slow if it were only driven by diffusion. However, CO2 mixes with the water to form a denser aqueous phase (e.g., ? ?? ~ 8 kg/m3 at 30 bars, see Gmelin, 1973). This initiates convective currents and increases the dissolution rate, which is equivalent to the dissolution of a larger amount of CO2 in a shorter period of time. The large volume of dissolved CO2 remains permanently in the aqueous phase (at least until the pressure remains unchanged) and poses no threat of leakage, which is favorable for geological storage of CO2.
We present and compare three different grid-based inversion methods for estimation of formation parameters and spatial geological feature identification based on pressure transient test (PTT) data from multiple-well locations. The first and second methods employ efficient adjoint schemes to determine the gradient of the objective functions resulting in the most likely set of reservoir parameters and an ensemble of updated realizations of the parameters, respectively. The second method is based on the Langevin equation. The third method uses ensemble Kalman filtering (EnKF) for data assimilation, in which the outcome is an ensemble of updated parameter realizations. These three methods use a grid-independent prior model (in view of the limited prior knowledge of the system expected to be available), described by as few parameters as possible, and consider a non-uniform grid with the highest resolution near the wells. With these methods, the existence of and location of many sub-seismic features such as strong spatial permeability variations, faults, fractures and pinch outs may be determined using exploration and production data. Such features may not be known a priori, particularly in the exploration of heterogeneous carbonate reservoirs.
We examine each method considering the degree of prior information required, the computational overhead and the applicability to the reservoir characterization workflow. Our results indicate that the first method provides a good history match to the observed PTT data and is suited for the early exploration phase of the reservoir. However, the parameters must be convolved with the smaller scale data to produce multiple realizations away from the implausibly smooth most-likely solution. The observed PTT data lies within the ensemble of predicted pressures in the EnKF and Langevin-based methods which are both applicable to probabilistic workflows where uncertainty is treated rigorously. However, EnKF seems to be computationally more efficient than the Langevin approach.