This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 179119, “A Well-Performance Study of Eagle Ford Gas Shale Wells Integrating Empirical Time/Rate and Analytical Time/Rate/Pressure Analysis,” by A.S. Davis and T.A. Blasingame, Texas A&M University, prepared for the 2016 SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, USA, 9–11 February. The paper has not been peer reviewed.
The purpose of the complete paper is to create a performance-based reservoir characterization by use of production data (measured rates and pressures) from a selected gas-condensate region within the Eagle Ford Shale. The authors use modern time/rate (decline-curve) analysis and time/rate/pressure (model-based) analysis methods to analyze, interpret, and diagnose gas-condensate well-production data. Reservoir and completion properties are estimated; these results are then correlated with known completion variables. The time/rate and time/rate/pressure analyses are used to forecast future production and to estimate ultimate recovery.
Production-Analysis Work Flow
The data required for the completion of the proposed methodology include well-history files, daily-rate and flowing-pressure measurements, and laboratory pressure/volume/temperature (PVT) and fluid-analysis reports. The following diagnostic plots are used to identify potential errors or abnormalities in the production data:
In addition to checking the integrity and correlation of production data, the authors also use the following diagnostic plots to establish the reservoir model and flow regimes:
Note that, for the diagnostic plots, an incorrect estimate of the initial reservoir pressure will yield plots that show skewed trends or clumping or scattering of data points, particularly at early production times.
On the basis of the information gathered from the diagnostic plots and well-history files, nonrepresentative production data points that are likely the result of nonreservoir effects or operational changes such as well-cleanup effects, liquid loading, well recompletions, well workovers, or choke changes are filtered. The diagnostic plots are prepared with the filtered production data to identify the flow regimes experienced by a given well. It is of primary importance to recognize if the well is still in transient flow or has already entered boundary- dominated flow because it allows determination of which of the time/rate relation models is appropriate for the given production data.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 183743, “Maintaining Injectivity of Disposal Wells: From Water Quality to Formation Permeability,” by Ali A. Al-Taq, Mohammed N. Al-Dahlan, and Abdullah A. Alrustum, Saudi Aramco, prepared for the 2017 SPE Middle East Oil and Gas Show and Conference, Manama, Bahrain, 6–9 March. The paper has not been peer reviewed.
An extensive laboratory study was carried out with two objectives: to evaluate the effect of water quality on injectivity of disposal wells with reservoir core plugs and to restore injectivity of damaged wells. In this paper, water-quality guidelines to minimize or prevent formation damage are recommended. On the basis of laboratory work, a novel chemical treatment was successfully applied to restore injectivity of several damaged disposal wells. This novel treatment reduced the long operation time and cost of a typical treatment practice while effectively stimulating the well.
Effect of Water Quality and Formation Permeability on Injectivity
Water quality has a major influence on the injectivity of injection and disposal wells. Poor injection or disposal-water quality can compromise the effective injectivity of even high-quality sandstone or carbonate formations. Source water used for injection often contains solids, which can reduce permeability of the formation around the wellbore.
Solids-particle damage depends on particle size of the solids, oil present in the injected water, and the average pore-throat diameter of the formation. If the particles are larger than the average pore-throat diameter of the formation, then the particles cannot penetrate the pores. As a result, an external filter cake with permeability lower than that of the formation will form (Fig. 1a). Another type of injectivity impairment occurs when the size of the particles present in the injected water is smaller than the average pore-throat diameter of the formation. These particles will invade the formation and bridge at some pores (Fig. 1b). As solids concentration in the injection water is increased, the rate of permeability decline becomes greater. Obviously, if the size of the particles is significantly smaller than the average pore-throat diameter of the formation (Fig. 1c), then the particles will flow through the formation without causing any damage. As a result, there will be no loss of injectivity for a long period of time.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 18914, “Extracting More From Wireline Formation Testing: Better Permeability Estimation,” by S.R. Ramaswami, P.W. Cornelisse, SPE, H. Elshahawi, M. Hows, and C.L. Dong, SPE, Shell, prepared for the 2016 International Petroleum Technology Conference, Bangkok, Thailand, 14–16 November. The paper has not been peer reviewed. Copyright 2017 International Petroleum Technology Conference. Reproduced by permission.
The use of pressure-transient data in formation testing to describe reservoirs is considered mature technology, particularly when applied to data collected through production testing. The extension of this technique to data obtained using wireline formation testers (WFTs) has been gaining momentum in the industry; however, the integration of these outputs with other measurements of data is not always straightforward. The complete paper presents different methods of using pressure-transient data from WFTs; many of these methods are summarized here.
Pressure-Transient Data From WFTs
Perhaps the most widely used form of WFT pressure-transient data is that derived from small-volume drawdowns and buildups during a pressure test. The volume of fluid withdrawn from the formation, and the resulting depth of the pressure pulse, is limited to the near-wellbore region. The flow regime that develops during these tests is typically spherical flow in an infinite medium; hence, the mobilities derived from these sorts of pressure-transient tests are spherical mobilities and need to be converted to radial mobilities to quantitatively compare the tests. Additionally, pretest-derived mobilities have two fundamental challenges: the unknown effect of skin caused by drilling damage and the uncertainty of fluid viscosity to be used to convert the resulting mobility to permeability.
The other common application of pressure-transient information during wireline-formation tests uses pressure data over a much longer interval. During an extended pumping station with a WFT, a particular flow-rate history is applied to a well and the resulting pressure changes are recorded. From the measured pressure response, and from predictions of how reservoir properties influence that response, an insight into the reservoir can be gained. In order to make these predictions, it is necessary to develop mathematical models of the physical behavior taking place in the reservoir. Fig. 1 shows the difference between the volume investigated with a small-volume pressure test and an extended pumpout station. The most-common well model that is used when interpreting WFT data is the vertical limited entry model.
Fluid flow in porous media is governed by the diffusivity equation. To derive it in its simplest form, the following assumptions and simplifications have to be made:
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 187263, “Modeling of Production Decline Caused by Fines Migration in Deepwater Reservoirs,” by Yunhui Tan, Yan Li, Ruiting Wu, Peggy Rijken, Karim Zaki, Oya Karazincir, Wade Williams, and Bin Wang, Chevron, prepared for the 2017 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 9–11 October. The paper has not been peer reviewed.
Many deepwater wells experience steep productivity declines. On the basis of field observations, this decline is partly attributed to fines-migration effects. The complete paper presents a numerical work flow to simulate the effect of flow-induced fines migration on production decline over time in deepwater reservoirs. This work flow will help reservoir engineers to predict the damage caused by fines migration, predict production decline, and plan remediation.
Although there are generally two causes of fines mobilization (or release), chemical (colloidal) and mechanical (hydrodynamical or flow), the complete paper focuses only on the mechanically induced fines migration, in which fines are mobilized by increasing flow velocity. As with chemically induced fines, there is a critical flow velocity at which fines are mobilized.
Previous studies focused on characterizing fines-migration processes by use of intricate mathematical models and adjustment of modeling parameters to match laboratory results. These models are mathematically complex and computationally expensive usually, which means they are applicable only to 1D simulation. To solve engineering problems, reservoir engineers need to perform realistic simulation on complex 3D geometries.
Fit to Laboratory Test Results. A fines-migration test includes coreflooding at several different rates. The rates are kept constant while pressure is allowed to change. Rate and pressures are recorded during the test. By use of this information and core dimensions and fluid properties, the permeability can be calculated with Darcy’s law. The total test time for the “standard” or conventional fines-migration test normally is 1 week. A recent study on fines migration determined that short-term (1-week) fines-migration tests were not long enough to observe fines migration in the laboratory; hence, the study recommended an extended-fines-migration (EFM) test as the new testing standard.
The EFM test normally runs for 3 weeks instead of 1 week. The longer time allows the permeability loss caused by the fines-migration damage to be separated from that caused by other factors. Also, a low-flow-rate step is introduced after reaching the highest designed rate to determine if the observed damage is caused by fines migration or by turbulent flow (non-Darcy flow). Fines migration occurs only when the flow velocity is greater than the critical velocity. The authors usually observed severe damage only at high flow velocity in the testing process. However, at high flow velocity, non-Darcy flow also takes place, thereby contributing to the permeability reduction. Therefore, it is important to add a step at a low velocity after the highest designed rate to determine the actual damage caused by fines migration.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 180181, “Catalog of Well-Test Responses in a Fluvial Reservoir System,” by J.L. Walsh and A.C. Gringarten, Imperial College London, prepared for the 2016 SPE Europec featured at the 78th EAGE Conference and Exhibition, Vienna, Austria, 30 May–2 June. The paper has not been peer reviewed.
Well-test analysis in fluvial reservoirs remains a challenge because of the depositional environment conducive to significant internal heterogeneity. Analytical models used in conventional analysis are limited to simplified channel geometries and, therefore, fail to capture key parameters such as sand-body dimensions, orientations, and connectivity, which can affect control-fluid flow and pressure behavior. The complete paper aims at a better understanding of the effect of channel content in complex fluvial channel systems on well-test-derivative responses.
Geological Modeling. 3D geological models with a centrally located well were generated and populated with varying fluvial geologies. A 6950-m×6950-m×300-ft geological model was set up that allowed the averaging effects of the heterogeneities and the reservoir boundaries to be visible on the derivative at late times.
Modeling the geology of a fluvial system is challenging because of changes in channel amplitude, amalgamation, and other processes through geological times, which yield highly variable distribution and shapes of fluvial deposits. Field X was modeled as isolated elliptical sand bodies and channel bodies, with sand-body dimensions of 105 m (width)×420 m (length)×5 ft (thickness) for the base case. The sand and channel bodies are schematically represented in Figs. 1 and 2. Object-oriented modeling was used instead of stochastic, sequential indicator simulation and Gaussian simulation to retain control over the modeling parameters.
Numerical Simulation. The corresponding pressure and derivative dynamic responses were generated using a proprietary finite-element simulator with a uniform grid and a fine local grid refinement (LGR) around the wellbore. The fluid was black oil at a reservoir pressure greater than the saturation pressure, and the relative permeability to water was low enough to limit water movement within the model.
Results and Discussion of Base-Case Model
A drawdown of 115 years was simulated for a geological model 6950 m×6950 m×300 ft with a cell size of 50 m×50 m×5 ft in the x, y, and z directions, respectively (total cell count without LGR=1,159,260), with a fine Cartesian LGR around the wellbore to reduce numerical artifacts around the wellbore (total cell count with LGR=1,327,200). The model consists of two facies. All simulations were performed without including wellbore dynamics or mechanical skin.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 185889, “The Nature of Drilling-Fluid Invasion, Cleanup, and Retention During Reservoir-Formation Drilling and Completion,” by Justin Green, Ian Patey, and Leigh Wright, Corex; Luca Carazza, Aker BP; and Arild Saasen, University of Stavanger, prepared for the 2017 SPE Bergen One Day Seminar, Bergen, Norway, 5 April. The paper has not been peer reviewed.
A reservoir-conditions coreflood study was undertaken to assist with design of drilling and completion fluids for a Norwegian field. Multiple fluids were tested, and the lowest permeability alterations did not correlate with the lowest drilling-fluid-filtrate-loss volumes. This paper will examine the factors that contributed to alterations in the core samples.
A range of measurements are made during reservoir-condition studies, with typical metrics of the performance of a fluid or sequence including the following:
These metrics are unfortunately subject to a number of factors that make interpretation difficult and therefore add risks to the decision-making process. In order to reduce these risks, a number of interpretive techniques are used. These include scanning electron microscopy (SEM), thin sections, and computed-tomography (CT) scanning.
In order to overcome some of the limitations posed by existing techniques, a micro-CT change-mapping technique was developed to show the distribution of alterations within samples at selected points in a study.
Do Filtrate Loss Volumes Tell Us How a Drilling Fluid Is Performing?
In terms of aiding operational decisions, the remaining mudcake attachment after a period of production or injection is most relevant in maximizing hydrocarbon recovery. The cleanup of drilling mudcakes will be influenced by a range of factors. An approach that allows a holistic view of the changes related to drilling fluid, taking into account as many relevant factors as possible, is therefore desirable.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 184716, “Successful Multiwell Deployment of a New Abandonment System for a Major Operator,” by Thore Andre Stokkeland and Jim McNicol, Archer Oiltools, and Gary McWilliam, Maersk Oil, prepared for the 2017 SPE/IADC Drilling Conference and Exhibition, The Hague, The Netherlands, 14–16 March. The paper has not been peer reviewed.
A new downhole-tool-based abandonment system was developed and deployed successfully on four wells for a major operator on a field in the North Sea. The operations were executed with each well taking less than 18.5 hours to secure. The successful operation saved the major operator considerable time and expense by eliminating the need for cutting and pulling the 10¾-in. casing to remove the oil-based mud (OBM) from the annulus before removing the wellheads.
Service companies were challenged by a major operator to create a solution to set a barrier against the overburden and to circulate OBM out of the annulus between the 10¾- and 13⅜-in. casings before pulling the wellhead.
The first stage of the operation was to run a perforation gun loaded for 1 ft with 18 shots/ft (spf) of a proprietary abandonment charge (single-casing perforation gun) to immediately below the wellhead at 475 ft. Then, the 10¾-in. casing was perforated with 0.8-in.-diameter holes without damaging the 13⅜-in. casing to create a circulation path.
The second stage was to run a retrievable bridge plug (RBP) with another 1-ft-long perforation gun below. The RBP was set and perforated immediately above the 13⅜-in. shoe at 2,300 ft; then, circulation was established up to the shallow perforations above and the OBM in the 10¾- by 13⅜-in. annulus was circulated out. After the circulation parameters were established, a wash pill was pumped around the annulus to clean out the OBM.
The third step was to set the actual overburden barrier in the A and B annuli. This was achieved by displacing cement through the ball valve of the RBP into the perforations below the RBP, placing the cement plug below and into the 10¾- by 13⅜-in. annulus. The ball valve was closed, and a cement plug was pumped on top of the RBP, completing the barrier.
The North Sea’s Leadon Field lies in 370 ft of water and is located in Blocks 9/14a and 9/14b of the UK Continental Shelf approximately 220 miles northeast of Aberdeen. Field development was enabled by the addition of two satellite fields, Birse and Glassel. The three fields were developed with subsea horizontal wells tied back to a floating production, storage, and offloading facility. The Lark and Horda formations produce in two well clusters, A and B. Cluster A has seven production wells and two water injectors; Cluster B consists of three production wells, two water injectors, and two aquifer wells. Both clusters have space for additional wells.
After a commercially successful period, production eventually declined, leading to a Cessation of Production Application being filed by the operator in 2004. A decommissioning program for the field was approved in March 2016.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 27921, “Risk-Based Approach to Well Plugging and Abandoning: Reducing Costs While Verifying Risk,” by Pedram Fanailoo, David Buchmiller, Simon Ouyang, and Eric Allen, DNV GL, prepared for the 2017 Offshore Technology Conference, Houston, 1–4 May. The paper has not been peer reviewed. Copyright 2017 Offshore Technology Conference. Reproduced by permission.
A risk-based approach to well plugging and abandonment (P&A) has been developed and successfully applied. The recommended method is based on research that allows the modeling of fluid flow through microcracks through a range of failure modes in downhole components, the determination of the effect on the environment through dispersion modeling, and identification of the basis for acceptance criteria. The complete paper describes how various P&A designs can be compared by use of a risk methodology that takes account of degradation mechanisms, potential flow rates, and the effect on the environment.
The application of the proposed method to fields suggests that alternative plugging solutions with fewer barriers than prescribed by the standard NORSOK D-010 guidelines result in the same low level of environmental risk. The method accounts for uncertainty related to input parameters and can be refined further if these uncertainties are reduced over time by field observations and testing.
The proposed approach to quantifying the environmental risk associated with minor, long-term leakage from P&A barriers, overburden formations, and natural seepage is to frame the issue in terms of potential modifications to valued environmental resources. This permits a degree of differentiation between alternative plugging designs, none of which may be physically capable of leading to the type of major leakage treated by standard environmental-risk-analysis approaches.
Description of Well-Abandonment Designs
General. Per NORSOK D-010, a P&A job should be planned and performed with an eternal perspective. Numerous regulations and requirements for different countries and areas of operation exist, but these generally state that there should be at least one permanent well barrier between a potential source of inflow and the surface.
A potential source of inflow is defined in the guideline as a formation with permeability, but not necessarily a reservoir. This requirement does not apply to the case in which the formation is a reservoir, with a reservoir defined as a permeable formation or group of formation zones originally within the same pressure regime, with a flow potential or hydrocarbons present or likely present in the future; in this case, the requirement is two permanent well barriers. These requirements can lead to confusion because NORSOK D-010 does not provide any further explanation of the terms “in-flow” and “flow potential.” Some major operators define “flow potential” as a formation with permeability and over-pressure, meaning that a reservoir can be a formation containing hydrocarbons, a formation with permeability and overpressure, or a combination of both. Furthermore, NORSOK D-010 holds that the last openhole section of a wellbore should not be abandoned permanently without installation of a permanent well barrier, often known as the surface P&A barrier.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 185640, “IOR Methods in Unconventional Reservoirs of North America: Comprehensive Review,” by Dheiaa Alfarge, Iraq Ministry of Oil and Missouri University of Science and Technology, and Mingzhen Wei and Baojun Bai, Missouri University of Science and Technology, prepared for the 2017 SPE Western Regional Meeting, Bakersfield, California, USA, 23–27 April. The paper has not been peer reviewed.
In the complete paper, three stages of review have been combined to find out the applicability of the most-feasible improved-oil-recovery (IOR) methods in North American unconventional reservoirs. The study found that the integration of experimental, simulation, and pilot-test tools is the proper technique to accurately diagnose the most-feasible IOR methods in these reservoirs; these methods, as indicated by the research, include carbon dioxide (CO2), surfactant, and natural-gas injection.
Review of Potential IOR Methods
The ultratight matrix and high conductivity of natural fractures might be the two most important factors that impair success of conventional IOR methods. The authors conducted a critical review of more than 70 studies aiming to find applicability of different IOR methods in unconventional reservoirs.
Chemical Methods. Generally, this category includes three methods: surfactant, polymer, and alkaline injection. Surfactant injection has the most-promising potential to improve oil recovery in North American unconventional reservoirs. These reservoirs are well-known as intermediate-wet to oil-wet; this type of rock affinity would prevent the aqueous phase from invading the matrix to displace the oil in place. Therefore, changing wettability and enhancing water imbibition through surfactant injection would be a good strategy to improve oil recovery.
To the authors’ knowledge, there has been no study conducted to investigate the applicability of polymer- and alkaline-injection methods in these types of unconventional reservoirs. It is believed that injectivity problems are the primary reason that no investigation has been conducted on applying polymer in these reservoirs, although conformance problems are more dominant in the reported pilot tests. Also, injecting polymer into these reservoirs would plug the pore throats, which are very small in these plays. Investigation of alkaline potential in these reservoirs has also not been conducted by reported studies. This could be because there is no compatibility between this chemical agent and the mineral-composition complexity of these reservoirs.
Smart-Waterflooding Technique. Recently, intensive studies have been conducted to investigate the effect on oil recovery of flooding with low-salinity water (LSW). It has been reported in different studies that maximum oil recovery can occur at optimal concentrations of salt for brine injected in cores (laboratory work) or in the field (simulation work). Wettability alteration and interfacial tension might be the main mechanisms behind the increment in oil recovery resulting from injection of LSW. However, the underlying mechanisms for wettability alteration are still controversial. Double-layer expansion and multicomponent ion exchange might be the main mechanisms behind wettability alteration because of the addition of salt. However, most of the reviewed studies focused on conventional reservoirs with high permeability.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 187369, “A New Three-Phase Microemulsion Relative Permeability Model for Chemical-Flooding Reservoir Simulators,” by Hamid R. Lashgari, Gary A. Pope, Mohsen Tagavifar, Haishan Luo, and Kamy Sepehrnoori, The University of Texas at Austin, and Zhitao Li and Mojdeh Delshad, Ultimate EOR Services, prepared for the 2017 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 8–11 October. The paper has not been peer reviewed.
The complete paper presents a new three-phase relative permeability model for use in chemical-flooding simulators. A model that has been widely used in chemical-flooding simulators for decades has numerical discontinuities that are not physical in nature and that can lead to oscillations in the numerical simulations. The proposed model is simpler, has fewer parameters, and requires fewer experimental data to determine the relative permeability parameters compared with the original model.
Two- and three-phase relative permeability measurements at low interfacial tension (IFT) have been published previously, and microemulsion relative permeability models have been proposed in the literature as well. But none of these can model the microemulsion phase across different phase-behavior environments, from oil-in-water, to the middle phase, to water-in-oil emulsions. Desirable features should include agreement between two- and three-phase micro emulsion relative permeability and oil-recovery data, and relative simplicity for use in reservoir simulators with a minimum number of model parameters that can be estimated from experimental data in a straightforward way. Satisfying these requirements has turned out to be an extremely challenging task.
The objective of this study was to develop a simple, continuous two- and three-phase microemulsion relative permeability model with relatively few parameters that is practical for use in chemical-flooding simulators. Discontinuities in relative permeability cause numerical problems that can cause severe reductions in the size of the timesteps. Discontinuities also cause errors in the physical predictions of important phenomena such as phase trapping and surfactant retention. The need for a continuous model has been well-known, but it was a challenging task to develop a continuous model because of the complexity of three-phase microemulsion phase behavior.