Drillstem/well testing

Decline curve analysis is widely used in industry to perform production forecasting and to estimate reserves volumes. A useful technique in verifying the validity of a decline model is to estimate the Arps decline parameters, the loss ratio and the b-factor, with respect to time. This is used to check the model fit and to determine the flow regimes under which the reservoir produces. Existing methods to estimate the b-factor are heavily impacted by noise in production data. In this work, we introduce a new method to estimate the Arps decline parameters.

We treat the loss ratio and the b-factor over time as parameters to be estimated in a Bayesian framework. We include prior information on the parameters in the model. This serves to regularize the solution and prevent noise in the data from being amplified. We then fit the parameters to the model using Markov chain Monte Carlo methods to obtain probability distributions of the parameters. These distributions characterize the uncertainty in the parameters being estimated. We then compare our method with existing methods using simulated and field data.

We show that our method produces smooth loss ratio and b-factor estimates over time. Estimates using the three-point derivative method are not matched with data, and results in biased estimates of the Arps parameters. This can lead to misleading fits in decline curve analysis and unreliable estimates of reserves. We show that our technique helps in identification of end of linear flow and start of boundary dominated flow. We use our method on simulated data, with and without noise. Finally, we demonstrate the validity of our method on field cases.

Fitting a decline curve using the loss ratio and b-factor plots is a powerful technique that can highlight important features in the data and the possible points of failure of a model. Calculating these plots using the Bourdet three-point derivative induces bias and magnifies noise. Our analysis ensures that this estimation is robust and repeatable by adding prior information on the parameters to the model and by calibrating the estimates to the data.

This paper presents a simple yet rigorous model and provides a methodology to analyze production data from wells exhibiting three-phase flow during the boundary-dominated flow regime. Our model is particularly applicable to analyze production data from volatile oil reservoirs, and should replace the less accurate single-phase models commonly used. The methodology will be useful in rate transient analysis and production forecasting for horizontal wells with multiple fractures in shales. Our analytical model for efficiently handling multi-phase flow is an adaptation of existing single-phase models. We introduce new three-phase parameters, notably fluids properties. We also define three-phase material balance pseudotime and three-phase pseudopressure to linearize governing flow equations. This linearization makes our model applicable to wells with variable rates and flowing pressures. We optimized the saturation-pressure path and further suggested an appropriate method to calculate three-phase pseudopressures. We validated the solutions through comparisons with compositional simulation using commercial software; the excellent agreement demonstrated the accuracy and utility of the analytical solution. We concluded that, during the boundary-dominated flow regime, the saturation-pressure relation given by steady-state path and tank-type model for volatile oil reservoirs leads to satisfactory results. We also confirmed that our definitions of three-phase fluid properties are well suited for ultra-low permeability volatile oil reservoirs. The computation time of our model is greatly reduced compared to a numerical approach, and thus the methodology should be attractive to the industry. Our model is efficient and practical to be applied for production data analysis in ultra-low permeability volatile reservoirs with non-negligible water production during the boundary-dominated flow regime. This study extends existing analytical model methodology for volatile oil reservoirs and is relatively easy for reservoir engineers to understand.

Due to the complexity of shale reservoir geology, hydraulic and micro-fractures can be coupled into an extremely complex symmetrical or asymmetrical fracture network around vertically fractured wells (VFW) after fracturing. The important and useful work is to analyze the transient pressure response of the VFW, to more accurately predict the productivity of VFW. In this paper, a numerical method to accurately simulate the complex fracture network geometry and analyze the transient pressure responses of the VFW, due to the complexity of the fracture network geometry. The results show a longer fracture length on one side causes a smaller pressure depletion, a shorter bilinear flow, and a deeper and longer the degree of "dip". The more fractures on one side can lead to a greater degree of "dip" and a smaller pressure depletion. With the fracture conductivity on the right side increases, while that in other side remains constant value, it results in a shorter bilinear flow, a deeper and longer the degree of "dip", a smaller pressure depletion, and a weaker bi-radial flow (BRF). In addition, it is found that flow regimes affected by magnitude of fracture networks are mainly bi-linear flow (BLF), "dip" and BRF. The pressure behaviors between asymmetrical fracture networks and symmetrical fracture networks are mainly in the periods of BLF, "dip", and BRF. Through analyzing the transient pressure responses of the VFW, the parameters of the complex fracture network can be well predicted, so that the productivity of the VFW can be estimated more accurately.

Magwa-Marrat reservoir fluid is an asphaltenic hydrocarbon, exhibiting precipitation and deposition of asphaltene in the production system including the reservoir rock near wellbore and the tubing. The main objective of this work was to optimize production in Magwa-Marrat wells by remediation of tubing plugging and formation damage. Well interventions were prioritized based on potential production benefit resulting from the removal of productivity impairment. It was required to understand current formation damage in all wells, including those without recent pressure transient analysis (PTA).

All PTA tests since 1983 for Magwa-Marrat reservoir were analyzed to determine the different reservoir parameters such as flow capacity (KH), Skin (S), reservoir boundaries, and the extrapolated reservoir pressure (P*). PTA derived permeability was compared to log derived permeability to quality control skin determination. Independently formation damage was estimated using the radial form of the solution of the diffusivity equation for pseudo steady state flow. Once a skin correlation for both PTA vs. Darcy's law equation was derived using out of date well performance, the formation damage for all wells was accessed using current productivity index to identify production optimization opportunities in wells without recent PTA. This work was combined with nodal analysis to separate vertical lifting performance and inflow performance relationship impact on total productivity detriment.

Cross plot of PTA derived flow capacity (Kh) vs. Log derived Kh correlates very well with a slope and a coefficient of correlation close to 1.0. This was observed for wells located in the reservoir where there are not heterogeneities near wellbore such as boundaries or natural fractures. For these cases the higher than normally observed estimated skin explained poorer well productivity. After skin values were accessed for all wells, a production gain was estimated, and the wells were ranked based on potential benefit. A stimulation campaign was put in place based on the type of rock, formation damage and vertical lifting performance. Eight (8) wells were stimulated and they delivered approximately an additional 20% production for the field.

This work was innovative in the sense that there was not pressure build up tests run prior to the interventions and such, there was not any production deferral. This was achieved by building the well performance understanding on a correlation that required petrophysical description, production rates and estimates of drainage area reservoir pressure.

Loss of barrier assurance and primary containment occurrences whether downhole or at surface have impacted safe well operation and production funnel significantly. Complex well head design, inadequate cement behind casing, threat of shallow gas presence and multiple downhole tubulars leaks are some of the common perils in sustaining the production. Apart from frequent pressure monitoring, risk assessment and mitigation plans to tackle the issues head-on, a new fresh perspective is required to manage well integrity and diagnostic holistically. This paper will highlight application of geochemical method as the new eye to trace source of well integrity issues and emulates forensic engineering to investigate well barrier failures.

Crude and gas compositional analysis from C1 up till C36 carbon chain plays a key role in determining the possible scenarios of leak paths and type of fluid expelled from the wellbore. The best forensic analysis could be produced utilizing multiple samples which represent different stages of well life starting from open-hole exploration drilling, development, production and towards the well abandonment stage. Comparing samples composition at each stage with reference to the baseline while evaluating the existing or newly acquired cement bond and diagnostic logs will help to complete the lingering puzzle.

Results showed that the origin of the fluid samples expelled from the wellbore are successfully traced in a much more economical way with faster turn-around time compared to the conventional diagnostic method. It helps to point out the most likely well integrity elemental failure which has triggered immediate actions to revive the production. Plan to feed in the cash flow has been accelerated 6 months ahead through work-over activities and number of unhealthy well strings has been reduced by 12%. Production deferment is also reduced by half million ringgit equivalent value.

In a nutshell, the case studies provide an eye-opening insight towards predictive and quantitative well integrity solutions to support production. Forward looking the geochemical forensic method can be further tailored for strategic well diagnostic solutions as more data comes in. Time to action could be further reduced with the introduction of advanced on-site analysis technology to boost the restoration efforts.

The acquisition of downhole pressure data representative of reservoir response enabling subsequent pressure transient analysis has been one of the primary drivers for running drill stem tests. However, many factors can influence the representativity and interpretability of the data acquired that are not related to reservoir properties.

To our knowledge, while many publications have presented challenges in acquiring representative pressure data those have not been compiled in a comprehensive revies, and there are no practical recommendations that would summarise causes and effects and offer procedures to eliminate or at least manage those effects and enable end-users to maximize the value of acquired data.

This paper describes in details today's challenges associated with the acquisition of high-quality, representative and undisturbed bottom hole pressure data during well test operations. Many different effects, including gauges’ deployment methods, wellbore effects and operational aspects of the test can compromise the quality of bottom hole data acquired while running a welltest.

Therefore, the origin and impact of each of these effects needs to be evaluated at the design stage of the test to develop appropriate mitigation actions. To address these issues, actual examples and methodologies derived from various locations are presented.

Over the years the metrological performances of downhole memory gauges such as resolution or drift have improved drastically, reaching a point where gauge specifications have become less influential on data quality than environmental effects. Many improvements have also been made in DST tools to increase the representativity and interpretability of acquired bottom hole pressure data such as the introduction of downhole shut-in valves or compensation for tubing contraction and expansion due to temperature change during the test. However, there remain several occurrences today where memory gauge data are affected by the various wellbore phenomena making interpretation of downhole pressure transient test data complicated. The selection of an appropriate location of pressure sensors in the DST string also remains a crucial task.

The paper provides analysis, explanations and practical recommendations allowing to mitigate the most common effects typically observed during welltest operations performed around the world, such as: –

Tidal effect

This paper will summarise the observation and lessons learned from hundreds of welltest operations performed around the globe with different reservoir fluids and environments through a few telling examples. Furthermore, the paper provides practically proven well-test techniques allowing to manage those adverse effects on bottom-hole pressure data. Recipes for success are provided to ensure that high-quality data can be acquired during welltest operations in a challenging environment while keeping the cost in line with the AFEs.

The standard modeling techniques for fractured wells were developed for conventional (higher permeability) reservoirs. The application of these techniques in fractal (shale) reservoirs often yield physically-inconsistent results which can cause over/mis-interpretation of the transient data. The purpose of this work is to provide a new modeling scheme using the "fractional integration" solution for hydraulically fractured wells producing from a fractal reservoir. This methodology takes into account the reservoir heterogeneity in the modeling of the fluid flow towards the hydraulic fracture and provides physically consistent diagnostic interpretations and parameters.

We have used the "fractional integration" approach to "couple" the fluid flow from a fractal (reservoir) to a Euclidean object (i.e., the hydraulic fracture). This approach requires rescaling the coordinate axes for the fractal reservoir using power-law relations.

In this work we derive generalized models that can reproduce the classic Euclidean hydraulic fracture scenarios. We studied the constant-rate and constant-pressure cases and found that our proposed models yield the following three flow periods:

Period 1: Early Fractal-Formation (EFF) flow. This flow period is analogous to the formation-linear flow for conventional reservoirs. The transient signature of this flow period is only influenced by the conductivity index (reservoir heterogeneity fractal parameter).

In performing this work, we provide the following technical contributions:

We introduce a physically-consistent modeling scheme for a well with uniform-flux vertical fracture producing from a fractal (shale) reservoir.

Well diagnostics in deep, offshore GoM are vital in order to interpret any issues related to productivity losses. This is especially important since any intervention in such wells is very costly. Multiphase flow is amongst leading causes of well productivity loss. This paper presents an integrated workflow that provides a solution to the challenge of quantifying multiphase PTA results in single and multiple commingled production cases. The workflow is used to monitor the performance of several wells over an extended period in a deep-water offshore reservoir under water/aquifer drive. It builds on a succession of PTA tests starting from single phase flow until water breakthrough and beyond. The results of historical PTA provided meaningful insights that were used as basis for actions that led to well and reservoir performance optimization.

Pre-salt heterogeneous carbonate reservoirs typically present long net pays, high production/injection rates and some flow assurance risks. This paper presents general information, results and lessons learned regarding the installation of Intelligent Well Completion (IWC) in Santos Basin Pre-Salt Cluster (SBPSC) wells. It also presents some important improvements to be introduced in the future IWC systems specification and qualification based on the lessons learnt in these projects, setting some new challenges to the industry.

The benefits expected with the use of IWC are achieved at the expense of challenging well engineering, since well completion design becomes more complex and well construction risks increase. Detailed and integrated planning is essential for the success of the operations, starting at the earliest phases of the well design and continued through detailed execution plans. The use of standardized practices and procedures has led to significant increases on installation performance. On the other hand, an open mind and a constant search for improvements allowed new solutions and procedures to be developed throughout the years. Regarding the system integration, a flexible and standardized control architecture was developed to allow combining different IWC providers and subsea vendors, which proved to be a successful approach.

The most important improvement in IWC installation was the anticipation of the acid stimulation, nowadays performed before the vertical Wet Christmas Tree (WCT) installation. In order to achieve this goal some crucial improvements were gradually implemented in the stimulation practices, such as, an initial injectivity increase solution and some new acid diversion solutions, which allowed eliminating the use of coiled tubing and, as a consequence, the need of a subsea test tree. The well design team conducted an integrated risk assessment to properly evaluate the new practices and establish some actions to reduce the risks. Intense communication between production zones was observed during the acid job in some of the initial wells, ruining the gains of the IWC. After a comprehensive analysis, some possible causes were identified and with the new stimulation practices this issue was eliminated.

Over the years, with the introduction of several improvements, some of them presented in this paper, the well completion duration was reduced to less than 50% of the one observed in the initial wells. This major performance increase has been essential to keep this deepwater projects feasible, especially in the oil scenario seen in recent years. Some of the new practices and lessons learned in this 100 wells equipped with IWC has set groundbreaking practices for Brazilian pre-salt fields development and may stand as a reference for the industry in similar deepwater projects. Additional requirements for future systems are expected to improve even further the performance in this scenario.

Hydrocarbon production from Shale formations has become an increasingly significant part of the global energy supply since 2010. With the advent of horizontal drilling and multiple-stage hydraulic fracturing, the Utica Shale, which underlies the Marcellus Shale as a natural source rock, is one of the most promising and productive shale plays in the US. However, very few academic papers discuss its geo-stress, pore pressure, permeability, and corresponding DFIT applications, which are essential for the development of the Utica Shale. The objective of this study is to use Diagnostic Fracture Injection Tests (DFITs) data from the field to analyze minimum in-situ stress, closure pressure, reservoir pore pressure, key reservoir properties and fracture geometry in the Utica Shale by different DFIT interpolation methods. The analysis results are compared and discussed in detail to investigate the features of each DFIT interpolation method. In addition, DFIT numerical simulation based on Variable Compliance Model is performed to predict induced fracture geometry and effective formation permeability in the Utica Shale.

DFIT is a commonly applied technique to analyze stress regimes and reservoir properties, while its interpolation can be challenging and difficult for different formations. DFIT interpretation for Shale formations is even more complex. In this study, first overviewing the geology of the Utica Shale and continuing to the summary of DFIT analysis and its governing equations, one can gain a better understanding of the methods and processes used to analyze our DFIT data targeting the Utica Shale. Tangent Line method, Compliance method, and Variable Compliance method are reviewed, and the corresponding assumptions for each method are examined, compared and discussed. Our DFIT data, which is acquired from a horizontal well targeting the Utica Shale, is interpreted by all methods to analyze minimum in-situ stress, closure pressure, initial reservoir pore pressure, key reservoir properties and fracture geometry. The DFIT results are then discussed and compared in detail to investigate the features of each method with its diagnostic signatures. Following that, the induced fracture geometry and the effective formation permeability are predicted by numerical simulation and sensitivity analysis, which also evaluate the impacts of wellbore storage, formation properties and fluid properties on simulated pressure and pressure derivative profiles.

The results from DFIT analysis are very encouraging. The Tangent Line method oversimplified leak off dependence and fracture stiffness, while the obtained minimum in-situ stress, closure pressure, pore pressure, fracture geometry and effective permeability are consistent with the diagnostic plots and our petrophysics studies. The Compliance method is able to identify mechanical closure, but it overestimates the minimum principal stress. The Variable Compliance method can capture the variance in fracture stiffness and pressure dependent leak off during progressive fracture closure, and its estimated closure pressure is an average of the results from the Tangent Line and the Compliance methods. The formation permeability of the Utica Shale is estimated by performing a history match of the pressure and pressure derivative profiles. The physics behind the DFIT simulation and sensitivity analysis is analyzed and discussed in detail. Our study can significantly improve the understanding of pressure/stress regimes, fracture geometry, and reservoir properties in the Utica Shale, as well as features of different DFIT interpolation methods. The knowledge and results demonstrated in this article will indefinitely assist operators in their optimization of multistage fracturing and horizontal drilling design in order to develop the Utica Shale more cost-effectively.