Lakatos, Istvan Janos (U. of Miskolc) | Lakatos-Szabo, Julianna (Research Institute of Appllied Earth Sciences, UM) | Kosztin, Bela (Petroleum Development of Oman) | Al-Sharji, Hamed Hamoud (Petroleum Development of Oman) | Ali, Ehtesham (Petroleum Development of Oman) | Al-Mujaini, Rahima Abdul Rauf (Petroleum Development of Oman) | Al-Alawi, Nasser (Petroleum Development of Oman)
In frame of the project, one injector and two oil producers operating in different reservoirs having extremely high permeability were treated using the silicate/polymer method. The well selection based on analysis of production history, reservoir structure, and tracer test and production characteristics. The water cut in producers was close to or well above 90%. The chemical system was individually tailored to each well. The gel-forming solutions were sequentially injected into the wells using bullhead technique. The producers operating with sucker rod pumping were treated through the producing tubing or the annulus. In the latter case, a new "virtual" reactor concept was elaborated to mix the solution on the fly. Evaluating the results, it can be concluded that the project was successful. The cumulative daily oil production increased by 68 m3/d; meanwhile the water production decreased by 285 m3/d. Thus, on yearly basis, the incremental oil production might be as high as ~25,000 m3/y with water production less than 105,000 m3/y. The project clearly proved that the silicate/polymer technology could meet the requirements of the unique reservoir conditions (extreme permeability, faulted structure, and low formation temperature). In addition, great advantage of the composite methods is that easily available, cheap, and environmental friendly chemicals were used.
Background of arising problems in Omani hydrocarbon production can be traced back to unfavorable types of reservoirs and properties of oils. Most of the oil bearing formations are faulted, highly heterogeneous with extremely high average permeability. In addition, the formation temperature is often low and the crude oils have high viscosity. Hence, the early water breakthrough and high water cut are often characterizing the production. Under these circumstances, the recovery factor is low, and poor well performance usually jeopardizes the optimal oil rate. Recognizing and understanding the production problems and forecasting their detrimental effects on deliverability, substantial efforts had been made recently to avoid production decline and mitigate the damaging processes. Among others, IOR/EOR methods addressing the whole reservoir space and well stimulation technologies were tested and routinely applied at different fields. In the frame of these endeavors, ambitious pilot tests were carried out to restrict water production in oil wells and simultaneously, to improve sweep efficiency in injectors through flow profile control. Earlier, diverse techniques including cementing, perforation relocation, polymer, and gel treatment were tested with partial success. The basic goal of the extensive field programs was to select the most efficient methods, which are flexible enough to meet the requirements at different oil fields. That strategy made the field tests of the silicate/polymer methods possible treating two producers and one injector. The company's idea also determined the target wells operating in different oil fields, hence under different, sometimes harsh formation conditions.
Most subterranean rocks contain natural fractures. Fluid loss severity in reservoir sections increases with increasing width of the fractures. Apart from the economics of lost drilling fluids, preventing formation damage in the reservoir section is of paramount importance. The application of non-damaging lost circulation material (LCM) has been the traditional solution to control losses in these scenarios. The performance of such LCM mixtures is usually determined with a Particle Plugging Apparatus (PPA), using aloxide discs for evaluating fluid loss. These discs more closely emulate a permeable sandstone, with varying pore throat sizes, than a natural fracture. The formation of an impermeable plug which can sustain higher wellbore pressure is desirable when treating a fracture, but in a producing formation the plug is removed by the produced fluid or by a remedial treatment.
To better emulate both natural and induced fracture geometry, slotted discs of constant width were introduced; however these slots represent only the face of the fracture where LCM forms the bridge. The bridge may become eroded due to shear stress of the drilling fluid, leading to reestablishment of lost circulation. To remove these limitations, a new tapered slot was designed in which the fracture opening size varies from its face to its endpoint over a certain length, more closely resembling a fracture.
Different combinations of ground marble (acid-soluble) were tested using the tapered slot. Many times it was observed that although the slot was completely filled with LCM, there was continued fluid loss. Considering this, components of high fluid loss pills for such application need to be redesigned. Cellulosic and polylactide (PLA) fibres (5-15% V/V of LCM) were used in combination with particulates resulting in significant improvement in fluid loss control. Other mechanical properties of particulate material were also studied and their importance in controlling lost circulation control established. This paper reviews the application of this testing equipment and methodology with non-damaging fibers for lost circulation control to minimize formation damage in reservoir sections.
Viscoelastic surfactant (VES) based self-diverting acid system has been developed for better matrix treatment of carbonate formations. Literature survey indicates that the highly viscous fluid acts as a temporary barrier to reduce further fluid loss into the wormholes and allows complete stimulation of all treating zones. After acid treatment, the viscous fluid is broken by either formation hydrocarbons or pre-flush fluids. However, recent lab work confirmed that a significant amount of surfactant was retained inside the core even when mutual solvent was used. The present study was conducted to better understand these acid systems and determine factors that impact their viscosity build-up and performance inside the carbonate formations.
A series of coreflood tests were conducted using carbonate cores at different injection rates. Propagation of the acid, surfactant, and reaction products inside the cores was examined in detail. Samples of the core effluent were collected and the concentrations of calcium, surfactant, and acid were measured. Permeability enhancement and location of any precipitation was detected using CT scanner to the core before and after the acid injection. Material balance was conducted to determine the amount of surfactant that retained in the core.
Experimental results show that VES acid was not able to buildup pressure drop across the core when it was injected inside 70 md permeability cores at various acid concentrations and injection rates when only one fourth pore volumes was injected. At high concentration of HCl, Calcium and the surfactant propagated with the same velocity. When low concentration of HCl was employed, Calcium propagated faster. Surfactant retention is higher when the acid concentration and the injection rate were lower. This number could be up to 100%. CT scan confirmed only small and short wormhole branches at the area near the inlet and one wormhole dominated till the end with a decreasing diameter. Reaction rate and extension of wormhole decreased when lower concentration HCl was used and injected at a higher rate.
Producing natural gas from shale gas reservoirs presents a great challenge to the petroleum engineers because of the low permeability nature of this type of gas reservoirs. Large scale and expensive hydraulic fracturing operations are often required for enhancing gas well productivity. Due to the shally characteristics of the reservoir rock, the hydraulically fractured gas wells are very vulnerable to the damage by the fracturing fluids. However, the significance of the formation damage due to different causes in fractured wells is still not clear. It is highly desirable to have a simple method for predicting the degree of fracture face matrix damage and optimizing fracturing treatment. This paper fills the gap.
A new mathematical model was developed in this study to predict the effect of fracture face matrix damage on productivity of fractured gas wells in shale gas reservoirs. A unique feature of the new model is that it considers reservoir-fracture crossflow in finite conductivity fractures. Results of the model analyses were sensitized to reservoir properties and facture face matrix skin properties determined by the fracturing fluid properties and treatment conditions. Large ranges of possible leakoff coefficient and spurt-loss coefficient were investigated. We concluded that the significance of fracture face matrix damage to well productivity depends on reservoir properties (porosity and permeability) and fracturing fluid properties (leakoff coefficient, spurt loss coefficient, and viscosity). Reservoir properties determine the vulnerability of formation damage, while fluid properties controls the degree of formation damage. The productivity index ratio (PIR) for describing the significance of formation damage drops non-linearly with leak-off coefficient and damage permeability ratios. In the practical range of the leak-off coefficient, the PIR analysis reveals that well productivity should drop by less than 15% even the residual permeability is 5% of the virgin reservoir permeability in the damage zone. Accurate prediction of the effect of fracture face matrix damage on well productivity with this model requires conducting laboratory test to determine the residual permeability in the damaged zone for a given shale gas reservoir.
Control of inorganic scale such as sulfate and carbonate has been possible via inhibitor chemical treatment or modification of the fluids types (i.e. desulfation of injection fluid). The deployment of scale inhibitor treatments via continual injection downhole and to topside process equipment is a common practice as it batch chemical treatments to production wells via the squeeze process.
The paper will outline the inhibitor selection process and field results for three oilfields (1) a conventional squeeze chemical selection study with coreflood and chemical placement evaluation for an application within two south American offshore fields and (2) non conventional batch chemical application for a West African offshore oilfield where scale inhibitor was applied within the fluids used to simulate the well prior to frac pack operation so providing initial scale inhibitor placement prior to initial water breakthrough. This non convention batch treatment eliminated a squeeze to these subsea wells and allowed uninterrupted production of oil until 850,000 bbls to 2,100,000 bbls of produced water was produced from the wells. The delay in applying the first squeeze to these wells allowed the water cut to increase above the relatively low water cut values (<10% BS&W) associated with slow clean up post an aqueous squeeze treatment.
This paper will present with the aid of field data from both fields how the challenges of managing scale forced innovation in terms of when to apply scale inhibitor to deepwater subsea wells within the fields. The paper will demonstrate that scale management while being complex can be controlled and treatment programs optimised with the use of varied monitoring methods and the varied skill of the scale management team members.
South American Field Cases
The fields are located in the Campos Basin offshore Brazil, approximately 145 km east of Macae, on the present-day continental slope, in water depths ranging from 700 to 850 m (Bogaert et. al, 2006; Bogaert et. al, 2007).
Development of Field X comprises 6 horizontal producers, gravel-packed with pre-packed screens, located centrally in the reservoir and 4 deviated water injectors at the flanks. Six production wells are located on two production manifolds; four injection wells are located on a single injection manifold. Field Y is 5 km to the northwest of Field X, and was developed in a similar manner, with two horizontal producers completed as in Field X, producing to one manifold, and two deviated water injectors tied back to another.
Both fields produce to the same FPSO, which has a production capacity of 81,000 bbl of oil per day and a storage capacity of 1.2 million barrels of oil. A third party operates the FPSO. The field came on stream in August 2003. Initial average production was some 60 kbpd but this dropped to 50 kbpd by early 2005 due to early breakthrough of injection water and well impairment.
Cleanup of filter cake is a difficult task and becomes more challenging when dealing with weighting materials such as manganese tetraoxide. Mn3O4 is a strong oxidizing agent and can be used as a catalyst due to its active phase, which will result in complex interactions with most cleaning fluids.
The reaction of selected organic acids and chelating agents with Mn3O4 particles as a function of time and temperature were studied. Atomic absorption was used to measure manganese concentrations and X-ray diffraction to analyze solids remaining after the reaction.
White precipitate of manganese citrate was produced following the reaction of citric acid with Mn3O4 up to temperatures of 284°F. The amount of precipitation increased with temperature and initial chelate concentration. GLDA reacted with Mn3O4 particles completely at 190°F. However, a large amount of white precipitation produced. Similarly, a white precipitation was observed with oxalic and tartaric acids. The reaction of DTPA with Mn3O4 particles in glass reactor produced Mn(silicates) at 212 and 284°F. This study will help drilling/completion engineers to avoid using such chemicals to prevent formation damage after filter cake removal treatments.
Accumulation of spent acid in the wellbore area after acidizing causes severe formation damage that would result in loss of productivity. This would cause reduction of relative permeability to gas, especially in tight gas wells. Capillary forces are the key parameters that affect trapping of spent acid in the formation. This work provides a comprehensive study of the effect of acid additives in spent acid on contact angle in tight gas carbonates. All experiments were conducted using the Drop Shape Analysis (DSA) at high temperature and pressure.
Different types of commonly used additives including corrosion inhibitors, iron control agents, mutual solvents, methanol, acetic acid and formic acid were tested at different concentrations. Experiments were conducted at temperature of 100 oC and pressure of 1000 psi.
Acid additives such as methanol, corrosion inhibitors, formic and acetic acids reduced the contact angle. Both iron control agents showed no impact on contact angle at concentration of 0.3 wt.% while at the lower concentration of 0.03 wt.% they decreased contact angle. A study was also done on the effect of temperature on contact angle of spent acid. The results showed that increasing temperature up to 100 oC increased contact angle, while beyond this temperature contact angle was decreased.
This work would help to better understand the ability of acid additives in altering wettability of carbonate rocks, which would consequently result in better designing the acid formulae and enhancement in well productivity by minimizing capillary forces.
Chanpura, Rajesh A. (Schlumberger) | Fidan, Selcuk (Stanford University) | Mondal, Somnath (U. of Texas at Austin) | Andrews, Jamie Stuart (Statoil ASA) | Martin, Frederic (Total) | Hodge, Richard M. (ConocoPhillips) | Ayoub, Joseph Adib (Schlumberger) | Parlar, Mehmet (Schlumberger) | Sharma, Mukul Mani (U. of Texas at Austin)
Slurry type sand retention tests (SRT) that simulate gradual rock failure around the wellbore have been widely used in the industry to evaluate the performance of sand control screens for standalone screen (SAS) applications. Using the test results, screen selection is generally done based on the relative ranking of screen performances rather than absolute performance.
A recent paper by Chanpura et al. (2011) highlighted the drawbacks of the current practices in slurry type SRT procedures and proposed a new testing and interpretation methodology. Another recent work by Mondal et al. (2010) proposed simulation methods and results that, to the best of our knowledge, modeled screen performance numerically for the first time and presented comparisons to physical experiments. However, the approach used by Mondal et al. considers cases where hole collapse occurs on wire wrap screens and simulates "prepack?? testing as opposed to slurry type tests considered in this work.
In this paper, we review the recent advancements in screen testing, interpretation and modeling for standalone screen applications, and present an analytical as well as a statistical (Monte Carlo) approach for prediction of sand production through sand screens with slot geometry. We show that the proposed methods can estimate both mass and size distribution of the produced solids in a slurry type SRT taking into account the full particle size distribution (PSD) of formation sand for wire wrap screens. Simulations show that once the slot opening is covered by particles bigger than the slot opening, sand production becomes negligible unless there is a true "fines?? problem, which is characterized by a bimodal size distribution. The effect of slot size variation in screen coupons on sand production demonstrates the importance of proper quality control or at least accurate determination of slot sizes in these tests. The proposed methods can be used to estimate sand production in slurry type SRT for different screen sizes and thereby enable screen size selection based on defined acceptable level of sand production. Final screen selection can be confirmed through a sand retention test.
Water flooding is the hinge pin for Gemsa Oil Field. Water injection is supplied from shallow water supply wells. Compatibility tests had indicated probable deposition of calcium sulphate scale on surface and subsurface production equipment. Calcium sulphate scale has been recognized to be a major operational problem. The bad consequences of scale formation comprised the contribution to flow restriction thus resulting in oil and gas production decrease. The nature of calcium sulphate scale is very hard and can't be dissolved with known dissolver. Sister companies that has similar problem were always going to the mechanical remover options (1).
Extensive lab and field work was conducted to determine the suitable chemicals to dissolve calcium sulphate scale.
This paper describes the development and field application of chemical treatment to remove scale in an offshore 8?? production line in Gemsa oil field. Continuous precipitation of calcium sulphate scale caused partial plugging of the pipeline. This partial plugging created a back pressure on production wells which decreased the productivity. The field production has been decreased to almost one tenth of the normal field production level.
A thorough investigation was conducted to identify the composition and location of the scale, in order to recommend a suitable chemical to remove the scale, and to assess the effectiveness of the treatment method in the field.
Based on extensive lab studies, Soda Ash was tested and applied in production line to remove the scale efficiently; the program was designed taking into consideration the nature of the scale.
API RP 19B Section 4 tests were established to evaluate perforator performance at field conditions. The question of how well such a small-scale laboratory test translates to downhole reality has long been raised. Furthermore, how accurately are downhole dynamics reproduced in single-shot, Section 4 tests, when in practice, an extensive formation is perforated with multiple shots?
To address this question, flow fields for typical axial and radial API Section 4 flow targets were calculated using a general analytical model based on potential theory and compared with the calculated results of various downhole configurations with different shot densities. When compared with calculations of downhole flow, we show that both radial and axial API targets can yield flow patterns that differ considerably from those downhole, which could lead to erroneous interpretations of results and dynamic effects, such as cleanup. As expected, results show that a radial flow target tends to overestimate the flow into a downhole perforation depending on the shot density and that an axial flow target tends to underestimate the flow depending on target length.
We discuss how to modify the API test core by attaching a low-permeability sleeve to create a more accurate downhole flow simulation. The result is a more representative test that better reproduces the initial static reservoir pressure and the post-shot flowing pressure.
To illustrate the concept, we made several tests using modified and unmodified axial flow targets to compare flow efficiency through perforations. Initial results indicate a difference in flow between the two sets of targets, with the modified targets having lower flow efficiency. Finally, we offer some possible physical reasons to explain the difference.